Southern California Gas Company PFD 6% (SOCGM) 10-K 2024 FY Annual report

0001032208sre:FirstMortgageBonds6125September152037Membersre:SanDiegoGasAndElectricCompanyMember2023-12-310001032208us-gaap:ForeignExchangeMemberus-gaap:FairValueHedgingMemberus-gaap:DesignatedAsHedgingInstrumentMembersre:EquityEarningsNetOfIncomeTaxMember2023-01-012023-12-31

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549 

FORM 10-K

(Mark One)
☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended	December 31, 2024
	or
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from		to

Commission File No.	Exact Name of Registrants as Specified in their Charters,  Address and Telephone Number		State of Incorporation	I.R.S. Employer Identification Nos.
1-14201	SEMPRA		California	33-0732627
	488 8th Avenue
	San Diego, California 92101
	(619) 696-2000
1-03779	SAN DIEGO GAS & ELECTRIC COMPANY		California	95-1184800
	8330 Century Park Court
	San Diego, California 92123
	(619) 696-2000
1-01402	SOUTHERN CALIFORNIA GAS COMPANY		California	95-1240705
	555 West 5th Street
	Los Angeles, California 90013
	(213) 244-1200

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of Each Class	Trading Symbol	Name of Each Exchange on Which Registered
SEMPRA:
Common Stock, without par value	SRE	New York Stock Exchange
5.75% Junior Subordinated Notes Due 2079, $25 par value	SREA	New York Stock Exchange
SAN DIEGO GAS & ELECTRIC COMPANY:
None
SOUTHERN CALIFORNIA GAS COMPANY:
None

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

Title of Each Class

SEMPRA:

None

SAN DIEGO GAS & ELECTRIC COMPANY:

None

SOUTHERN CALIFORNIA GAS COMPANY:

6% Preferred Stock, $25 par value

6% Preferred Stock, Series A, $25 par value

Indicate by check mark if the Registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.
	Yes	☒	No	☐
Indicate by check mark if the Registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
	Yes	☐	No	☒
Indicate by check mark whether the Registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
	Yes	☒	No	☐
Indicate by check mark whether the Registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrants were required to submit such files).
	Yes	☒	No	☐
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Sempra:
☒ Large Accelerated Filer	☐ Accelerated Filer	☐ Non-accelerated Filer	☐ Smaller Reporting Company	☐ Emerging Growth Company
San Diego Gas & Electric Company:
☐ Large Accelerated Filer	☐ Accelerated Filer	☒ Non-accelerated Filer	☐ Smaller Reporting Company	☐ Emerging Growth Company
Southern California Gas Company:
☐ Large Accelerated Filer	☐ Accelerated Filer	☒ Non-accelerated Filer	☐ Smaller Reporting Company	☐ Emerging Growth Company

If an emerging growth company, indicate by check mark if the Registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the Registrants have filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

2024 Form 10-K | 2

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the Registrants included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the Registrants’ respective executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the Registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
	Yes	☐	No	☒

Aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant computed by reference to the price at which the common equity was last sold as of June 28, 2024, the last business day of each Registrant’s most recently completed second fiscal quarter:
Sempra	$48.1 billion
San Diego Gas & Electric Company	$0
Southern California Gas Company	$0

Common stock, without par value, outstanding as of February 19, 2025:

Sempra	651,457,249 shares
San Diego Gas & Electric Company	Wholly owned by Enova Corporation, which is wholly owned by Sempra
Southern California Gas Company	Wholly owned by Pacific Enterprises, which is wholly owned by Sempra
SAN DIEGO GAS & ELECTRIC COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY GENERAL INSTRUCTION I(2).

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the Sempra proxy statement to be filed for its May 2025 annual meeting of shareholders are incorporated by reference into Part III of this annual report on Form 10-K.

Portions of the Southern California Gas Company information statement to be filed for its June 2025 annual meeting of shareholders are incorporated by reference into Part III of this annual report on Form 10-K.

2024 Form 10-K | 3

SEMPRA FORM 10-K
SAN DIEGO GAS & ELECTRIC COMPANY FORM 10-K
SOUTHERN CALIFORNIA GAS COMPANY FORM 10-K
TABLE OF CONTENTS
		Page
Glossary		5
Information Regarding Forward-Looking Statements		9
Summary of Risk Factors		11
PART I
Item 1.	Business	12
Item 1A.	Risk Factors	38
Item 1B.	Unresolved Staff Comments	62
Item 1C.	Cybersecurity	62
Item 2.	Properties	64
Item 3.	Legal Proceedings	64
Item 4.	Mine Safety Disclosures	64
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	65
Item 6.	(Reserved)	65
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	66
	Overview	66
	Results of Operations by Registrant	67
	Capital Resources and Liquidity	82
	Critical Accounting Estimates	101
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	105
Item 8.	Financial Statements and Supplementary Data	107
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	108
Item 9A.	Controls and Procedures	108
Item 9B.	Other Information	112
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	112
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	112
Item 11.	Executive Compensation	112
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	113
Item 13.	Certain Relationships and Related Transactions, and Director Independence	113
Item 14.	Principal Accountant Fees and Services	114
PART IV
Item 15.	Exhibits and Financial Statement Schedules	115
Item 16.	Form 10-K Summary	126
Signatures		127
Index to Consolidated Financial Statements		F-1
Index to Condensed Financial Information of Parent		S-1

This combined Form 10-K is separately filed by Sempra, San Diego Gas & Electric Company and Southern California Gas Company. Information contained herein relating to any one of these individual Registrants is filed by such entity on its own behalf. Each such Registrant makes statements herein only as to itself and its consolidated entities and makes no statement whatsoever as to any other entity.

You should read this report in its entirety as it pertains to each respective Registrant. No one section of the report deals with all aspects of the subject matter. A separate Part II – Item 8 is provided for each Registrant, except for the Notes to Consolidated Financial Statements, which are combined for all the Registrants. All Items other than Part II – Item 8 are combined for the three Registrants.

2024 Form 10-K | 4

The following terms and abbreviations appearing in this report have the meanings indicated below.

GLOSSARY
AB	California Assembly Bill
ADIA	Black Silverback ZC 2022 LP (assignee of Black River B 2017 Inc.), a wholly owned affiliate of Abu Dhabi Investment Authority
AFUDC	allowance for funds used during construction
amparo	an extraordinary constitutional appeal governed by Articles 103 and 107 of the Mexican Constitution and filed in Mexican federal court
AOCI	accumulated other comprehensive income (loss)
ARO	asset retirement obligation
ASC	Accounting Standards Codification
ASEA	Agencia de Seguridad, Energía y Ambiente (Mexico’s National Agency for Industrial Safety and Environmental Protection)
ASR	accelerated share repurchase
ASU	Accounting Standards Update
ATM	at-the-market equity offering program pursuant to the Sales Agreement
Bcf	billion cubic feet
Bechtel	Bechtel Energy Inc.
bps	basis points
California ISO adder	an additional 0.50% ROE for participation in the California ISO
Cameron LNG JV	Cameron LNG Holdings, LLC
Cameron LNG Phase 1 facility	Cameron LNG JV liquefaction facility
Cameron LNG Phase 2 project	Cameron LNG JV liquefaction expansion project
CARB	California Air Resources Board
CCA	Community Choice Aggregation
CCM	cost of capital adjustment mechanism
CEC	California Energy Commission
CFE	Comisión Federal de Electricidad (Mexico’s Federal Electricity Commission)
CFIN	Cameron LNG FINCO, LLC, a wholly owned and unconsolidated affiliate of Cameron LNG JV
CNBV	Comisión Nacional Bancaria y de Valores (Mexico’s National Banking and Securities Commission)
CODM	chief operating decision maker as defined in ASC 280
ConocoPhillips	ConocoPhillips Company
CPUC	California Public Utilities Commission
CRE	Comisión Reguladora de Energía (Mexico’s Energy Regulatory Commission)
CRR	congestion revenue right
DA	Direct Access
DER	distributed energy resources
DOE	U.S. Department of Energy
DOT	U.S. Department of Transportation
DWR	California Department of Water Resources
ECA LNG	ECA LNG Phase 1 and ECA LNG Phase 2, collectively
ECA LNG Phase 1	ECA LNG Holdings B.V.
ECA LNG Phase 2	ECA LNG II Holdings B.V.
ECA Regas Facility	Energía Costa Azul, S. de R.L. de C.V. LNG regasification facility
Ecogas	Ecogas México, S. de R.L. de C.V.
Edison	Southern California Edison Company, a subsidiary of Edison International
EFH	Energy Future Holdings Corp. (renamed Sempra Texas Holdings Corp.)
EPA	U.S. Environmental Protection Agency
EPC	engineering, procurement and construction
EPS	earnings (losses) per common share
ERCOT	Electric Reliability Council of Texas, Inc., the ISO and the regional coordinator of various electricity systems within Texas
ESJ	Energía Sierra Juárez, S. de R.L. de C.V.
ETR	effective income tax rate
Exchange Act	Securities Exchange Act of 1934, as amended

2024 Form 10-K | 5

GLOSSARY
FD	final decision
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings, Inc.
FTA	Free Trade Agreement
GCIM	Gas Cost Incentive Mechanism
GHG	greenhouse gas
GRC	General Rate Case
HOA	Heads of Agreement
IEnova	Infraestructura Energética Nova, S.A.P.I. de C.V.
IEnova Pipelines	IEnova Pipelines, S. de R.L. de C.V.
IMG	Infraestructura Marina del Golfo
INEOS	INEOS Energy Trading Limited, a subsidiary of INEOS Limited
IOU	investor-owned utility
IRA	Inflation Reduction Act of 2022
IRS	U.S. Internal Revenue Service
ISFSI	independent spent fuel storage installation
ISO	Independent System Operator
ITC	investment tax credit
JV	joint venture
KKR Denali	KKR Denali Holdco LLC, an affiliate of Kohlberg Kravis Roberts & Co. L.P.
KKR Pinnacle	KKR Pinnacle Investor L.P., an affiliate of Kohlberg Kravis Roberts & Co. L.P.
kV	kilovolt
kW	kilowatt
kWh	kilowatt hour
LA Fires	the wildfires in Los Angeles County, California, including the Palisades, Eaton and other fires, that burned in January and February of 2025
Leak	the leak at the SoCalGas Aliso Canyon natural gas storage facility injection-and-withdrawal well, SS25, discovered by SoCalGas on October 23, 2015
LNG	liquefied natural gas
LPG	liquid petroleum gas
LTIP	long-term incentive plan
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Mexican Stock Exchange	Bolsa Mexicana de Valores, S.A.B. de C.V., or BMV
MMBtu	million British thermal units (of natural gas)
MMcf	million cubic feet
Moody’s	Moody’s Investors Service, Inc.
MOU	Memorandum of Understanding
Mtpa	million tonnes per annum
MW	megawatt
MWh	megawatt hour
NAV	net asset value
NCI	noncontrolling interest(s)
NDT	nuclear decommissioning trusts
NEIL	Nuclear Electric Insurance Limited
NEM	net energy metering
NOL	net operating loss
NRC	Nuclear Regulatory Commission
NYSE	New York Stock Exchange
O&M	operation and maintenance expense
OCI	other comprehensive income (loss)
OEIS	Office of Energy Infrastructure Safety
OII	Order Instituting Investigation
Oncor	Oncor Electric Delivery Company LLC

2024 Form 10-K | 6

GLOSSARY
Oncor Holdings	Oncor Electric Delivery Holdings Company LLC
ORLEN	Polski Koncern Naftowy Orlen S.A.
Other Sempra	All Sempra consolidated entities, except for SDG&E and SoCalGas
PA LNG Phase 1 project	initial phase of the Port Arthur LNG liquefaction project
PA LNG Phase 2 project	second phase of the Port Arthur LNG liquefaction project
PBOP	postretirement benefits other than pension
PEMEX	Petróleos Mexicanos (Mexican state-owned oil company)
PG&E	Pacific Gas and Electric Company
PHMSA	Pipeline and Hazardous Materials Safety Administration
Port Arthur LNG	Port Arthur LNG, LLC, a subsidiary of SI Partners that owns the PA LNG Phase 1 project
PP&E	property, plant and equipment
PPA	power purchase agreement
PRP	Potentially Responsible Party
PUCT	Public Utility Commission of Texas
PURA	Texas Public Utility Regulatory Act
Rating Agencies	Moody’s, S&P and Fitch, collectively
REC	renewable energy certificate
Registrants	has the meaning set forth in Rule 12b-2 under the Exchange Act and consists of Sempra, SDG&E and SoCalGas for purposes of this report
ROE	return on equity
ROU	right-of-use
RPS Program	Renewables Portfolio Standard program
RSU	restricted stock unit
S&P	S&P Global Ratings, a division of S&P Global Inc.
Sales Agreement	ATM Equity Offering Sales Agreement, dated November 6, 2024, among Sempra and Barclays Capital Inc., BofA Securities, Inc., Citigroup Global Markets Inc., Goldman Sachs & Co. LLC, J.P. Morgan Securities LLC, Mizuho Securities USA LLC, Morgan Stanley & Co. LLC, MUFG Securities Americas Inc., RBC Capital Markets, LLC, Scotia Capital (USA) Inc., and Wells Fargo Securities, LLC (each a sales agent or forward seller) and Barclays Bank PLC, Bank of America, N.A., Citibank, N.A., Goldman Sachs & Co. LLC, JPMorgan Chase Bank, National Association, Mizuho Markets Americas LLC, Morgan Stanley & Co. LLC, MUFG Securities EMEA plc, Royal Bank of Canada, The Bank of Nova Scotia and Wells Fargo Bank, National Association, or one of their respective affiliates (each a forward purchaser)
SB	California Senate Bill
scope 1 emissions	a company’s direct emissions from operations that it owns or controls
scope 2 emissions	a company's indirect emissions such as purchased electricity for its own use at its facilities
scope 3 emissions	a company’s indirect emissions that are not included in scope 2 and that occur in the company’s value chain, including both upstream and downstream emissions
SDG&E	San Diego Gas & Electric Company
SDSRA	Senior Debt Service Reserve Account
SEC	U.S. Securities and Exchange Commission
SEDATU	Secretaría de Desarrollo Agrario, Territorial y Urbano (Mexico’s agency in charge of agriculture, land and urban development)
SEFE	SEFE Marketing & Trading México S. de R.L. de C.V.
SENER	Secretaría de Energía de México (Mexico’s Ministry of Energy)
series A preferred stock	6% mandatory convertible preferred stock, series A
series B preferred stock	6.75% mandatory convertible preferred stock, series B
series C preferred stock	Sempra’s 4.875% fixed-rate reset cumulative redeemable perpetual preferred stock, series C
Sharyland Holdings	Sharyland Holdings, L.P.
Sharyland Utilities	Sharyland Utilities, L.L.C.
Shell	Shell México Gas Natural, S. de R.L. de C.V.
SI Partners	Sempra Infrastructure Partners, LP, the holding company for most of Sempra’s subsidiaries not subject to California or Texas utility regulation
SoCalGas	Southern California Gas Company
SOFR	Secured Overnight Financing Rate
SONGS	San Onofre Nuclear Generating Station
SPA	sale and purchase agreement
SST Committee	Safety, Sustainability and Technology Committee of the Sempra board of directors

2024 Form 10-K | 7

GLOSSARY
Support Agreement	support agreement, dated July 28, 2020 and amended in June 2021 and January 2025, between Sempra and Sumitomo Mitsui Banking Corporation
TAG Norte	TAG Norte Holding, S. de R.L. de C.V.
TAG Pipelines	TAG Pipelines Norte, S. de R.L. de C.V.
Tangguh PSC	Tangguh PSC Contractors
TCEQ	Texas Commission on Environmental Quality
TdM	Termoeléctrica de Mexicali
TO5	Electric Transmission Owner Formula Rate, effective June 1, 2019
TO5 adder refund provision	the provision in the TO5 settlement providing that SDG&E will refund the California ISO adder as of June 1, 2019 if the FERC issues an order ruling that California IOUs are no longer eligible for the California ISO adder
TO6	Electric Transmission Owner Formula Rate, new application
TTI	Texas Transmission Investment LLC, an entity indirectly owned by OMERS Administration Corporation (acting through its infrastructure investment entity, OMERS Infrastructure Management Inc.) and GIC Private Limited
U.S. GAAP	generally accepted accounting principles in the United States of America
VaR	value at risk
VAT	value-added tax
Ventika	Ventika, S.A.P.I. de C.V. and Ventika II, S.A.P.I. de C.V., collectively
VIE	variable interest entity
Wildfire Fund	the fund established pursuant to AB 1054
Wildfire Legislation	AB 1054 and AB 111

In this report, references to “Sempra” are to Sempra and its consolidated entities, collectively, and references to “we,” “our,” “us” and “our company” are to the applicable Registrant and its consolidated entities, collectively, in each case unless otherwise stated or indicated by the context. All references in this report to our reportable segments are not intended to refer to any legal entity with the same or similar name.

Throughout this report, we refer to the following as Consolidated Financial Statements and Notes to Consolidated Financial Statements when discussed together or collectively:

▪the Consolidated Financial Statements and related Notes of Sempra;

▪the Financial Statements and related Notes of SDG&E; and

▪the Financial Statements and related Notes of SoCalGas.

2024 Form 10-K | 8

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are based on assumptions about the future, involve risks and uncertainties, and are not guarantees. Future results may differ materially from those expressed or implied in any forward-looking statement. These forward-looking statements represent our estimates and assumptions only as of the filing date of this report. We assume no obligation to update or revise any forward-looking statement as a result of new information, future events or otherwise.

Forward-looking statements can be identified by words such as “believe,” “expect,” “intend,” “anticipate,” “contemplate,” “plan,” “estimate,” “project,” “forecast,” “envision,” “should,” “could,” “would,” “will,” “confident,” “may,” “can,” “potential,” “possible,” “proposed,” “in process,” “construct,” “develop,” “opportunity,” “preliminary,” “initiative,” “target,” “outlook,” “optimistic,” “poised,” “positioned,” “maintain,” “continue,” “progress,” “advance,” “goal,” “aim,” “commit,” or similar expressions, or when we discuss our guidance, priorities, strategies, goals, vision, mission, projections, intentions or expectations.

Factors, among others, that could cause actual results and events to differ materially from those expressed or implied in any forward-looking statement include:

▪California wildfires, including potential liability for damages regardless of fault and any inability to recover all or a substantial portion of costs from insurance, the Wildfire Fund, rates from customers or a combination thereof

▪decisions, denials of cost recovery, audits, investigations, inquiries, ordered studies, regulations, denials or revocations of permits, consents, approvals or other authorizations, renewals of franchises, and other actions, including the failure to honor contracts and commitments, by the (i) CPUC, CRE, DOE, FERC, IRS, PUCT and other regulatory bodies and (ii) U.S., Mexico and states, counties, cities and other jurisdictions therein and in other countries where we do business

▪the success of business development efforts, construction projects, acquisitions, divestitures, and other significant transactions, including risks related to (i) being able to make a final investment decision, (ii) completing construction projects or other transactions on schedule and budget, (iii) realizing anticipated benefits from any of these efforts if completed, (iv) obtaining third-party consents and approvals and (v) third parties honoring their contracts and commitments

▪changes to our capital expenditure plans and their potential impact on rate base or other growth

▪litigation, arbitration, property disputes and other proceedings, and changes (i) to laws and regulations, including those related to tax and the energy industry in Mexico, (ii) due to the results of elections, and (iii) in trade and other foreign policy, including the imposition of tariffs by the U.S. and foreign countries

▪cybersecurity threats, including by state and state-sponsored actors, of ransomware or other attacks on our systems or the systems of third parties with which we conduct business, including the energy grid or other energy infrastructure

▪the availability, uses, sufficiency, and cost of capital resources and our ability to borrow money or otherwise raise capital on favorable terms and meet our obligations, which can be affected by, among other things, (i) actions by credit rating agencies to downgrade our credit ratings or place those ratings on negative outlook, (ii) instability in the capital markets, and (iii) fluctuating interest rates and inflation

▪the impact on affordability of SDG&E’s and SoCalGas’ customer rates and their cost of capital and on SDG&E’s, SoCalGas’ and Sempra Infrastructure’s ability to pass through higher costs to customers due to (i) volatility in inflation, interest rates and commodity prices, (ii) with respect to SDG&E’s and SoCalGas’ businesses, the cost of meeting the demand for lower carbon and reliable energy in California, and (iii) with respect to Sempra Infrastructure’s business, volatility in foreign currency exchange rates

▪the impact of climate policies, laws, rules, regulations, trends and required disclosures, including actions to reduce or eliminate reliance on natural gas, increased uncertainty in the political or regulatory environment for California natural gas distribution companies, the risk of nonrecovery for stranded assets, and uncertainty related to emerging technologies

▪weather, natural disasters, pandemics, accidents, equipment failures, explosions, terrorism, information system outages or other events, such as work stoppages, that disrupt our operations, damage our facilities or systems, cause the release of harmful materials or fires or subject us to liability for damages, fines and penalties, some of which may not be recoverable through regulatory mechanisms or insurance or may impact our ability to obtain satisfactory levels of affordable insurance

2024 Form 10-K | 9

▪the availability of electric power, natural gas and natural gas storage capacity, including disruptions caused by failures in the transmission grid or pipeline and storage systems or limitations on the injection and withdrawal of natural gas from storage facilities

▪Oncor’s ability to reduce or eliminate its quarterly dividends due to regulatory and governance requirements and commitments, including by actions of Oncor’s independent directors or a minority member director

▪other uncertainties, some of which are difficult to predict and beyond our control

We caution you not to rely unduly on any forward-looking statements. You should review and carefully consider the risks, uncertainties and other factors that affect our businesses as described herein and in other reports we file with the SEC.

2024 Form 10-K | 10

SUMMARY OF RISK FACTORS

There are a number of risks you should understand before making an investment decision in our securities or the securities of our subsidiaries. This summary is not intended to be complete and should only be read together with the information set forth in “Part I – Item 1A. Risk Factors” in this report. If any of these risks occurs, Sempra’s and its subsidiaries’ results of operations, financial condition, cash flows and/or prospects could be materially adversely affected, and the trading price of Sempra’s securities and those of its subsidiaries could decline. These risks include the following:

Risks Related to Sempra

▪Sempra’s ability to pay dividends and meet its obligations largely depends on the performance of its subsidiaries and entities accounted for as equity method investments

▪Successfully completing our five-year capital expenditures plan is subject to certain risks

▪The economic interest, voting rights and market value of our outstanding common and preferred stock may be adversely affected by any additional equity securities we may issue

Risks Related to All Sempra Businesses

▪Our businesses are subject to risks arising from their infrastructure and systems that support this infrastructure

▪We face risks related to severe weather, natural disasters, physical attacks and other similar events

▪We face evolving cybersecurity and technology resiliency risks associated with the energy grid, pipelines, storage and other infrastructure as well as the collection of personal, sensitive and confidential information

▪Our debt service obligations expose us to risks and could require additional equity securities issuances by Sempra or sales of equity interests in subsidiaries or projects under development

▪The availability and cost of debt or equity financing could be negatively affected by market and economic conditions and other factors

▪Credit rating agencies may downgrade our credit ratings or place them on negative outlook

▪We face risks related to failures and delays in obtaining and maintaining permits, licenses, franchises and other approvals required by our businesses

▪We face risks related to environmental and climate change regulation and the costs of the energy transition

▪We are subject to complex tax and accounting requirements that expose us to risks

Risks Related to Sempra California

▪Wildfires in California pose risks to Sempra, SDG&E and SoCalGas

▪The electricity industry is undergoing significant change, including increased deployment of renewable energy sources and energy storage, technological advancements, evolving procurement service standards, and political and regulatory developments

▪Natural gas continues to be the subject of political and public debate, including a desire by some to reduce or eliminate reliance on natural gas as an energy source

▪SDG&E and SoCalGas are subject to extensive regulation

Risks Related to Sempra Texas Utilities

▪Certain ring-fencing measures, governance mechanisms and commitments limit our ability to influence the management, operations and policies of Oncor

▪Changes in the regulation of Oncor or the regulation or operation of the electric utility industry and/or the ERCOT market could negatively affect Oncor

Risks Related to Sempra Infrastructure

▪Project development activities may not be successful, projects under construction may not be completed on schedule or within budget, and completed projects may not operate at expected levels or generate expected earnings or cash flows

▪We face risks from increased competition

▪We may not be able to secure, maintain, extend or replace long-term supply, sales or capacity agreements

▪Sempra Infrastructure’s business is capital-intensive and relies on various types of financing arrangements, which may not be adequate or available in the future

▪Our international businesses and operations expose us to increased legal, regulatory, tax, economic, geopolitical, credit and management oversight risks and challenges

2024 Form 10-K | 11

PART I.

ITEM 1. BUSINESS

OVERVIEW

We are a California-based holding company with energy infrastructure investments in North America. Our businesses invest in, develop and operate energy infrastructure, and provide electric and gas services to customers.

Sempra was formed in 1998 through a business combination of Enova Corporation and Pacific Enterprises, the holding companies of our regulated public utilities in California: SDG&E, which began operations in 1881, and SoCalGas, which began operations in 1867. We have since expanded our regulated public utility presence into Texas through our 80.25% interest in Oncor and 50% interest in Sharyland Utilities. Sempra Infrastructure’s assets include investments in the U.S. and Mexico with a focus on LNG, energy networks and low carbon solutions.

Business Strategy

Our mission is to be North America’s premier energy infrastructure company. We are primarily focused on transmission and distribution investments, among other areas, that we believe are capable of producing stable cash flows and earnings visibility, with the goals of delivering safe, reliable and increasingly clean forms of energy affordably to customers and increasing shareholder value.

DESCRIPTION OF BUSINESS BY SEGMENT

Sempra’s business activities are organized under the following reportable segments:

▪Sempra California

▪Sempra Texas Utilities

▪Sempra Infrastructure

SDG&E and SoCalGas each has one reportable segment.

2024 Form 10-K | 12

Sempra California

SDG&E

SDG&E is a regulated public utility that provides electric services to a population of, at December 31, 2024, approximately 3.6 million and natural gas services to approximately 3.3 million of that population, covering an approximate 4,100 square mile service territory in Southern California that encompasses San Diego County and an adjacent portion of Orange County.

SDG&E’s assets at December 31, 2024 covered the following territory:

We describe SDG&E’s electric utility operations below. We describe SDG&E’s natural gas utility operations below in “Sempra California’s Natural Gas Utility Operations.” For a discussion of the risks and uncertainties facing SDG&E’s business, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California.”

Electric Transmission and Distribution System. Service to SDG&E’s customers is supported by its electric transmission and distribution system, which includes substations and overhead and underground lines. These electric facilities are primarily in the San Diego, Imperial and Orange counties of California, and in Arizona and Nevada and consisted of 2,021 miles of transmission lines, 24,149 miles of distribution lines and 159 substations at December 31, 2024. Occasionally, various areas of the service territory require expansion to accommodate customer growth and maintain reliability and safety.

SDG&E’s 500-kV Southwest Powerlink transmission line, which is shared with Arizona Public Service Company and Imperial Irrigation District, extends from Palo Verde, Arizona to San Diego, California. SDG&E’s share of the line is 1,163 MW, although it can be less under certain system conditions. SDG&E’s Sunrise Powerlink is a 500-kV transmission line constructed by SDG&E and operated by the California ISO. Both of these lines together provide SDG&E with import capability of 3,900 MW of power.

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Mexico’s Baja California transmission system is connected to SDG&E’s system via two 230-kV interconnections with combined capacity of up to 600 MW in the north-to-south direction and 800 MW in the south-to-north direction. However, it can be less under certain system conditions.

SDG&E’s system is connected to Edison’s transmission system via five 230-kV transmission lines.

Electric Resources. SDG&E supplies power from its own electric generation facilities and procures power on a long-term basis from other suppliers for resale through CPUC-approved PPAs or purchases on the spot market. SDG&E does not earn any return on commodity sales volumes. SDG&E’s electric resources at December 31, 2024 were as follows:

ELECTRIC RESOURCES(1)
	Contract expiration date	Net operating  capacity (MW)	% of total
SDG&E:
Owned generation facilities, natural gas(2)		1,204	24	%
PPAs:
Renewable energy:
Wind	2025 to 2042	918	19
Solar	2030 to 2042	1,526	31
Other	2025 and thereafter	155	3
Tolling and other	2025 to 2042	1,113	23
Total		4,916	100	%

(1)    Excludes approximately 367 MW of energy storage owned and approximately 632 MW of energy storage contracted.

(2)    SDG&E owns and operates four natural gas-fired power plants, three of which are in California and one is in Nevada.

Charges under contracts with suppliers are based on the amount of energy received or are tolls based on available capacity. Tolling contracts are PPAs under which SDG&E provides natural gas to the energy supplier.

SDG&E procures natural gas under short-term contracts for its owned generation facilities and for certain tolling contracts associated with PPAs. Purchases from various southwestern U.S. suppliers are primarily priced based on published monthly bid-week indices, which can be subject to volatility.

SDG&E participates in the Western Systems Power Pool, which includes an electric-power and transmission-rate agreement that allows access to power trading with more than 300 member utilities, power agencies, energy brokers and power marketers throughout the U.S. and Canada. Participants can make power transactions on standardized terms, including market-based rates, preapproved by the FERC. Participation in the Western Systems Power Pool is intended to assist members in managing power delivery and price risk.

Customers and Demand. SDG&E provides electric services through the generation, transmission and distribution of electricity to the following customer classes:

ELECTRIC CUSTOMER METERS AND VOLUMES
	Customer meter count	Volumes(1) (millions of kWh)
	December 31,	Years ended December 31,
	2024	2024	2023	2022
SDG&E:
Residential	285,881	1,348	2,004	3,940
Commercial	31,313	1,363	1,868	2,850
Industrial	319	441	670	909
Street and highway lighting	1,574	55	77	101
	319,087	3,207	4,619	7,800
CCA and DA	1,213,258	13,484	12,228	9,900
Total	1,532,345	16,691	16,847	17,700

(1)    Includes intercompany sales.

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SDG&E currently provides procurement service for a portion of its customer load. Most customers receive electric procurement service from a load-serving entity other than SDG&E through programs such as CCA and DA. In such cases, SDG&E no longer procures energy for this departed load. Accordingly, SDG&E’s CCA and DA customers receive primarily transportation and distribution services from SDG&E.

CCA is only available if a customer’s local jurisdiction (city or county) offers such a program, and DA is currently limited by a cap based on gigawatt hours. Several jurisdictions in SDG&E’s territory have implemented CCA, including the City of San Diego in 2022. Additional jurisdictions may be considering CCA.

As a result of customers electing CCA and DA services, SDG&E’s historical energy procurement commitments for future deliveries exceed the needs of its remaining bundled customers. To help achieve the goal of ratepayer indifference (as to whether customers’ energy is procured by SDG&E or by CCA or DA), the CPUC revised the Power Charge Indifference Adjustment framework. The framework is intended to more equitably allocate SDG&E’s procurement cost obligations among customers served by SDG&E and customers now served by CCA and DA.

San Diego’s mild climate and SDG&E’s robust energy efficiency programs contribute to lower consumption by our customers. Rooftop solar installations continue to reduce residential and commercial volumes sold by SDG&E. At December 31, 2024, 2023 and 2022, the residential and commercial rooftop solar capacity in SDG&E’s territory totaled 2,318 MW, 2,154 MW and 1,864 MW, respectively.

Electricity demand is dependent on the health and expansion of the Southern California economy, prices of alternative energy products, consumer preference, environmental regulations, legislation, renewable power generation, the effectiveness of energy efficiency programs, demand-side management impact and DER. California’s energy policy supports increased electrification, particularly electrification of vehicles, which could significantly increase sales volumes in the coming years. Other external factors, such as the price of purchased power, the use and further development of renewable energy sources and energy storage, the development of or requirements for new natural gas supply sources, demand for and supply of natural gas and general economic conditions, can also result in significant shifts in the market price of electricity, which may in turn impact demand. Electricity demand is also impacted by seasonal weather patterns (or “seasonality”), tending to increase in the summer months to meet the cooling load and in the winter months to meet the heating load.

Competition. SDG&E faces competition to serve its customer load from distributed and local power generation growth, including DER. In addition, the electric industry is undergoing rapid technological change, and third-party energy storage alternatives and other technologies may increasingly compete with SDG&E’s traditional transmission and distribution infrastructure in delivering electricity to consumers. Certain FERC transmission development projects are open to competition, allowing independent developers to compete with incumbent utilities for the construction and operation of transmission facilities.

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SoCalGas

SoCalGas is a regulated public utility that owns and operates a natural gas distribution, transmission and storage system that delivers natural gas to a population of, at December 31, 2024, approximately 21.1 million, covering an approximate 24,000 square mile service territory that encompasses Southern California and portions of central California (excluding San Diego County, the City of Long Beach and the desert area of San Bernardino County).

SoCalGas’ assets at December 31, 2024 covered the following territory:

We describe SoCalGas’ natural gas utility operations below in “Sempra California’s Natural Gas Utility Operations.” For a discussion of the risks and uncertainties facing SoCalGas’ business, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California.”

Sempra California’s Natural Gas Utility Operations

Natural Gas Procurement and Transportation. At December 31, 2024, SoCalGas’ natural gas facilities included 3,037 miles of transmission and storage pipelines, 52,567 miles of distribution pipelines, 48,999 miles of service pipelines and nine transmission compressor stations, and SDG&E’s natural gas facilities consisted of 188 miles of transmission pipelines, 9,201 miles of distribution pipelines, 6,794 miles of service pipelines and one compressor station.

SoCalGas’ and SDG&E’s gas transmission pipelines interconnect with four major interstate pipeline systems: El Paso Natural Gas, Transwestern Pipeline, Kern River Pipeline Company, and Mojave Pipeline Company, allowing customers to bring gas supplies into the SoCalGas gas transmission pipeline system from the various out-of-state gas producing basins. Additionally, an interconnection with PG&E’s intrastate gas transmission pipeline system allows gas to flow into SoCalGas’ gas transmission pipeline system. SoCalGas’ gas transmission pipeline system also has an interconnect with a Mexican gas pipeline company at Otay Mesa on the California/Mexico border that allows gas to not only flow south from the gas producing basins in the southwestern U.S., but to also flow north into SoCalGas’ gas transmission pipeline system from supplies in Mexico. There are also several in-state gas interconnections allowing for delivery of California-produced gas, including a number of direct connections from biomethane producers.

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SoCalGas purchases natural gas under short-term and long-term contracts and on the spot market for SDG&E’s and SoCalGas’ core customers. SoCalGas purchases natural gas from various sources, including from Canada, the U.S. Rockies and the southwestern regions of the U.S. Purchases of natural gas are primarily priced based on published monthly bid week indices, which can be subject to volatility. The cost of purchases of natural gas for SDG&E’s and SoCalGas’ core customers is billed to those customers without markup.

To support the delivery of natural gas supplies to its distribution system and to meet the needs of customers, SoCalGas has firm and variable interstate pipeline capacity contracts that require the payment of fixed and variable tariffed and negotiated reservation charges to reserve firm and interruptible transportation rights. Energy companies, primarily El Paso Natural Gas Company, Transwestern Pipeline Company and Kern River Gas Transmission Company, provide transportation services into SoCalGas’ intrastate transmission system for supplies purchased by SoCalGas.

Natural Gas Storage. SoCalGas owns four natural gas storage facilities with a combined working gas capacity of 137 Bcf and 126 injection, withdrawal and observation wells that provide natural gas storage service. SoCalGas’ and SDG&E’s core customers, along with certain third-party market participants, are allocated a portion of SoCalGas’ storage capacity. SoCalGas uses the remaining storage capacity for load balancing services for all customers and for storage for noncore customers. Natural gas withdrawn from storage is important to help maintain service reliability during peak demand periods, including consumer heating needs in the winter, as well as peak electric generation needs in the summer. The Aliso Canyon natural gas storage facility has a storage capacity of 86 Bcf and, subject to CPUC limitations, represents 63% of SoCalGas’ working natural gas storage capacity. At December 31, 2024, SoCalGas has been authorized by the CPUC to utilize up to 68.6 Bcf of working gas at the facility.

Customers and Demand. SoCalGas and SDG&E sell, distribute and transport natural gas. SoCalGas purchases and stores natural gas for its core customers in its territory and SDG&E’s territory on a combined portfolio basis. SoCalGas also offers natural gas transportation and storage services for others.

NATURAL GAS CUSTOMER METERS AND VOLUMES
	Customer meter count	Volumes (Bcf)(1)
	December 31,	Years ended December 31,
	2024	2024	2023	2022
SDG&E:
Residential	886,031
Commercial	29,009
Electric generation and transportation	3,312
Natural gas sales		45	48	45
Transportation		38	39	39
Total	918,352	83	87	84
SoCalGas:
Residential	5,940,904
Commercial	248,866
Industrial	23,833
Electric generation and wholesale	38
Natural gas sales		304	321	304
Transportation		522	549	586
Total	6,213,641	826	870	890

(1)    Includes intercompany sales.

For regulatory purposes, end-use customers are classified as either core or noncore customers. Core customers are primarily residential and small commercial and industrial customers.

Most core customers purchase natural gas directly from SoCalGas or SDG&E. While core customers are permitted to purchase their natural gas supplies from producers, marketers or brokers, SoCalGas and SDG&E are obligated to maintain adequate delivery capacity to serve the requirements of all their core customers.

SoCalGas’ noncore customers consist primarily of electric generation, wholesale, and large commercial and industrial customers. A portion of SoCalGas’ noncore customers are non-end-users, which include wholesale customers consisting primarily of other utilities, including SDG&E, or municipally owned natural gas distribution systems. Noncore customers at SDG&E consist primarily of electric generation and large commercial customers.

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Noncore customers are responsible for procuring their natural gas requirements, as the regulatory framework does not allow SoCalGas and SDG&E to recover the cost of natural gas procured and delivered to noncore customers.

Natural gas demand largely depends on the health and expansion of the Southern California economy, prices of alternative energy products, consumer preference, environmental regulations, legislation, California’s energy policy supporting increased electrification and renewable power generation, and the effectiveness of energy efficiency programs. Other external factors such as weather, the price of, demand for, and supply sources of electricity, the use of and further development of renewable energy sources and energy storage, development of or requirements for new natural gas supply sources, demand for natural gas outside California, storage levels, transport capacity and availability of supply into California and general economic conditions can also result in significant shifts in the market price of natural gas, which may in turn impact demand.

One of the larger drivers of natural gas demand is electric generation. Natural gas-fired electric generation within Southern California (and demand for natural gas supplied to such plants) competes with electric power generated throughout the western U.S. Natural gas transported for electric generating plant customers may be affected by the overall demand for electricity, growth in self-generation from rooftop solar, the addition of more efficient gas technologies, new energy efficiency initiatives, and the degree to which regulatory changes in electric transmission infrastructure investment divert electric generation from SoCalGas’ and SDG&E’s service areas. The demand for natural gas may also fluctuate due to volatility in the demand for electricity due to seasonality, weather conditions and other impacts, and the availability of competing supplies of electricity, such as renewable energy sources. Given the significant level and availability of natural gas-fired generation, we believe natural gas is a dispatchable fuel that can continue to help provide electric reliability in our California service territories.

The natural gas distribution business is subject to seasonality. Demand for natural gas in our service territory typically rises during the winter months to accommodate heating needs and the summer months to support peak electric generation. As is prevalent in the industry, subject to regulatory limitations, SoCalGas typically injects natural gas into storage during the months of April through October and usually withdraws natural gas from storage during the months of November through March.

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Sempra Texas Utilities

Sempra Texas Utilities is comprised of our equity method investments in Oncor Holdings and Sharyland Holdings. Oncor Holdings is a wholly owned entity of Sempra that owns an 80.25% interest in Oncor. TTI owns the remaining 19.75% interest in Oncor. Sempra owns a 50% interest in Sharyland Holdings, which owns a 100% interest in Sharyland Utilities.

Sempra Texas Utilities’ assets at December 31, 2024 covered the following territory:

For a discussion of risks and uncertainties related to our equity method investments in Oncor Holdings and Sharyland Holdings, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Texas Utilities.”

Oncor

Oncor is a regulated electricity transmission and distribution utility that operates in the north-central, eastern, western and panhandle regions of Texas. Oncor delivers electricity to end-use consumers through its electrical systems and also provides transmission grid connections to merchant generation facilities and interconnections to other transmission grids in Texas. Oncor’s transmission and distribution assets are located in over 120 counties and more than 400 incorporated municipalities, including the

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cities of Dallas and Fort Worth and surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler, Temple, Killeen and Round Rock, among others. Most of Oncor’s power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way pursuant to permits, public utility easements, franchise or other agreements or as otherwise permitted by law.

At December 31, 2024, Oncor had 5,094 employees, including 836 employees covered under a collective bargaining agreement and excluding interns.

Certain ring-fencing measures, governance mechanisms and commitments, which we describe in “Part I – Item 1A. Risk Factors,” are in effect and are intended to enhance Oncor Holdings’ and Oncor’s separateness from their owners and to mitigate the risk that these entities would be negatively impacted by the bankruptcy of, or other adverse financial developments affecting, their owners. Sempra does not control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and commitments limit our ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends or other distributions, strategic planning and other important corporate issues and actions, including limited representation on the Oncor Holdings and Oncor boards of directors. Because Oncor Holdings and Oncor are managed independently (i.e., ring-fenced), we account for our 100% ownership interest in Oncor Holdings as an equity method investment.

Electricity Transmission. Oncor’s electricity transmission business is responsible for the safe and reliable operations of its transmission network and substations. These responsibilities consist of the construction, maintenance and security of transmission facilities and substations and the monitoring, controlling and dispatching of high-voltage electricity over its transmission facilities in coordination with ERCOT, which we discuss below in “Regulation – Utility Regulation – ERCOT Market.”

At December 31, 2024, Oncor’s transmission system included approximately 18,324 circuit miles of transmission lines, a total of 1,288 transmission and distribution substations, and interconnection to 192 third-party generation facilities totaling 58,597 MW.

Transmission revenues are provided under tariffs approved by either the PUCT or, to a small degree related to limited interconnection to other markets, the FERC. Network transmission revenues compensate Oncor for delivery of electricity over transmission facilities operating at 60 kV and above. Other services offered by Oncor through its transmission business include system impact studies, facilities studies, transformation service and maintenance of transformer equipment, substations and transmission lines owned by other parties.

Electricity Distribution. Oncor’s electricity distribution business is responsible for the overall safe and reliable operation of distribution facilities, including electricity delivery, power quality, security and system reliability. These responsibilities consist of the ownership, management, construction, maintenance and operation of the electricity distribution system within its certificated service area. Oncor’s distribution system receives electricity from the transmission system through substations and distributes electricity to end-users and wholesale customers through 3,757 distribution feeders at December 31, 2024.

Oncor’s distribution system included more than four million points of delivery at December 31, 2024 and consisted of 125,975 circuit miles of overhead and underground lines.

Distribution revenues from residential and small business users are generally based on actual monthly consumption (kWh) and distribution revenues from large commercial and industrial users are based on, depending on size and annual load factor, either actual monthly demand (kW) or the greater of actual monthly demand (kW) or 80% of peak monthly demand during the prior eleven months.

Customers and Demand. Oncor operates the largest transmission and distribution system in Texas based on the number of end-use customers and miles of transmission and distribution lines, delivering electricity to more than four million homes and businesses, operating more than 144,000 circuit miles of transmission and distribution lines as of December 31, 2024 in a territory with an estimated population of approximately 13 million. The majority of consumers of the electricity Oncor delivers are free to choose their electricity supplier from retail electric providers who compete for their business. Oncor is not a seller of electricity, nor does it purchase electricity for resale. Rather, Oncor provides wholesale transmission services to its electricity distribution business as well as non-affiliated electricity distribution companies, electric cooperatives and municipally owned utilities. Oncor also provides distribution services, consisting of retail delivery services to retail electric providers that sell electricity to end-use customers, as well as wholesale delivery services to electric cooperatives and municipally owned utilities. At December 31, 2024, Oncor’s distribution business customers primarily consisted of over 100 retail electric providers that sell the electricity it distributes to consumers in its certificated service areas.

Oncor’s revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer.

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Competition. Oncor operates in certificated areas designated by the PUCT. The majority of Oncor’s service territory is single certificated, with Oncor as the only certificated electric transmission and distribution provider. However, in multi-certificated areas of Texas, Oncor competes with certain other utilities and rural electric cooperatives for the right to serve end-use customers. In addition, the electric industry is undergoing rapid technological change, and third-party DER and other technologies may increasingly compete with Oncor’s traditional transmission and distribution infrastructure in delivering electricity to consumers.

Sharyland Utilities

Sharyland Utilities is a regulated electric transmission utility that owns and operates, at December 31, 2024, approximately 64 miles of electric transmission lines in south Texas, including a direct current line connecting Mexico and assets in McAllen, Texas. Sharyland Utilities is responsible for providing safe, reliable and efficient transmission and substation services and investing to support infrastructure needs in its service territory, which we discuss below in “Regulation – Utility Regulation – ERCOT Market.” Transmission revenues are provided under tariffs approved by the PUCT.

Sempra Infrastructure

Our Sempra Infrastructure segment includes the operating companies of our subsidiary, SI Partners, as well as a holding company and certain services companies. SI Partners is included within our Sempra Infrastructure reportable segment but is not the same in its entirety as the reportable segment. Sempra Infrastructure develops, builds, operates and invests in energy infrastructure to help provide safe, sustainable and reliable access to cleaner energy in markets in the U.S., Mexico and globally.

At December 31, 2024, Sempra, KKR Pinnacle and ADIA each hold a 70%, 20%, and 10% interest, respectively, in SI Partners. SI Partners owns a 100% interest in Sempra LNG Holding, LP and a 99.9% interest in IEnova at December 31, 2024.

The minority partners in SI Partners and Sempra are parties to the second amended and restated agreement of limited partnership of SI Partners (the LP Agreement). Under the LP Agreement, matters are decided generally by majority vote and the managers designated by the partners of SI Partners each vote on an equity-weighted basis based on the ownership percentage of their respective designating limited partner. SI Partners and its controlled subsidiaries are prohibited from taking certain limited actions without the prior written approval of the minority partners. The LP Agreement contains certain default remedies if any limited partner fails to fund any amounts required to be funded under the LP Agreement and requires that SI Partners distribute to the limited partners at least 85% of distributable cash of SI Partners and its subsidiaries on a quarterly basis, subject to certain exceptions and reserves. Generally, distributions from SI Partners are made on a pro rata basis. However, KKR Pinnacle is entitled to certain priority distributions in the event of material deviations between certain specified projected cash flows and actual cash flows. Additionally, the minority partners are entitled to certain priority distributions in the event a specified project that reaches a positive final investment decision does not have projected internal rates of return greater than a specified threshold or in the event Sempra has not made a positive final investment decision by a certain date on specified LNG projects that are under development. Under the LP Agreement, if the minority partners approve Sempra’s request that a project not be pursued jointly, or if the minority partners decide not to participate in any proposed project for which Sempra nevertheless desires to make a positive final investment decision, then Sempra may proceed with such project either independently through a different investment vehicle or as a “Sole Risk Project” within SI Partners and receive Sole Risk Interests in respect thereof. Sole Risk Projects are separated from other SI Partners projects and are conducted at Sempra’s sole cost, expense and liability, and Sempra receives, through the acquisition of Sole Risk Interests, the economic and other benefits, if any, from such projects.

Sempra Infrastructure consolidates Sempra’s ownership and management of its non-U.S. utility, energy infrastructure assets in North America under a single platform. These assets include LNG and natural gas infrastructure in the U.S. and Mexico and renewable energy, LPG and refined products infrastructure in Mexico, which are managed through three business lines: LNG, Energy Networks and Low Carbon Solutions.

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At December 31, 2024, Sempra Infrastructure owned or held interests in the following assets:

For a discussion of the risks and uncertainties facing Sempra Infrastructure’s business, see “Part 1 – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure.”

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LNG

Sempra Infrastructure’s LNG business line is comprised of a natural gas liquefaction and regasification portfolio in operation, construction or development, and is focused on securely delivering natural gas to markets around the world. Sempra Infrastructure’s development and/or construction of projects, which we describe below, is subject to numerous risks and uncertainties.

Cameron LNG Phase 1 Facility. SI Partners owns 50.2% of Cameron LNG JV, resulting in Sempra Infrastructure holding a 35.1% interest in the JV. An affiliate of TotalEnergies SE, an affiliate of Mitsui & Co., Ltd., and Japan LNG Investment, LLC (a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha) each own 16.6% of Cameron LNG JV. We account for our ownership interest in Cameron LNG JV under the equity method. No single owner controls or can unilaterally direct significant activities of Cameron LNG JV.

Cameron LNG JV owns and operates the Cameron LNG Phase 1 facility, a natural gas liquefaction, export, regasification and import facility with three natural gas pre-treatment, processing and liquefaction trains. The Cameron LNG Phase 1 facility is located in Hackberry, Louisiana, along the Calcasieu Ship Channel, which handles significant industrial shipping, including large oil and LNG tankers, that we believe is well positioned to supply the Atlantic and Pacific markets. The three liquefaction trains have a combined nameplate capacity of 13.9 Mtpa of LNG with an export capacity of 12 Mtpa of LNG, or approximately 1.7 Bcf of natural gas per day. The Cameron LNG Phase 1 facility has 20-year liquefaction and regasification tolling capacity agreements in place with affiliates of TotalEnergies SE, Mitsubishi Corporation and Mitsui & Co., Ltd., which collectively subscribe for the full nameplate capacity of the three trains at the facility.

ECA Regas Facility. SI Partners owns and operates the ECA Regas Facility in Baja California, Mexico, which is capable of processing one Bcf of natural gas per day and has a storage capacity of 320,000 cubic meters in two tanks of 160,000 cubic meters each.

The ECA Regas Facility generates revenues from firm storage service fees under firm storage service agreements and nitrogen injection service agreements with Shell and SEFE that expire in May 2028 and December 2025, respectively, which permit them to collectively use 50% of the terminal’s capacity, with the remaining 50% of the capacity available for Sempra Infrastructure’s use. The land on which the ECA Regas Facility and the ECA LNG liquefaction projects under construction and in development are expected to be situated, as well as land adjacent to those properties, are the subject of litigation. We discuss litigation, regulatory and other matters that could impact the ECA Regas Facility and the ECA LNG liquefaction projects in Note 15 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors.”

Sempra Infrastructure uses its 50% capacity at the ECA Regas Facility to satisfy its obligation under an LNG SPA with Tangguh PSC through 2029, which we discuss below, and ECA LNG Phase 1 will be the sole user of this capacity thereafter.

ECA LNG Phase 1 Project. SI Partners owns an 83.4% interest in ECA LNG Phase 1, resulting in Sempra Infrastructure holding a 58.4% interest in the project. An affiliate of TotalEnergies SE owns the remaining 16.6% interest in the project. ECA LNG Phase 1 is constructing a one-train natural gas liquefaction facility at the site of Sempra Infrastructure’s existing ECA Regas Facility with a nameplate capacity of 3.25 Mtpa and an initial offtake capacity of 2.5 Mtpa. We expect the ECA LNG Phase 1 project to commence commercial operations in the spring of 2026.

ECA LNG Phase 1 has definitive 20-year SPAs with an affiliate of TotalEnergies SE for approximately 1.7 Mtpa of LNG and Mitsui & Co., Ltd. for approximately 0.8 Mtpa of LNG.

PA LNG Phase 1 Project. SI Partners, KKR Denali and an affiliate of ConocoPhillips own a 28%, 42% and 30% interest, respectively, in the PA LNG Phase 1 project under construction on a greenfield site in the vicinity of Port Arthur, Texas, located along the Sabine-Neches waterway. Sempra Infrastructure holds a 19.6% interest in the project. The PA LNG Phase 1 project will consist of two liquefaction trains, two LNG storage tanks, a marine berth and associated loading facilities and related infrastructure necessary to provide liquefaction services with a nameplate capacity of approximately 13 Mtpa and an initial offtake capacity of approximately 10.5 Mtpa. We expect the first and second trains of the PA LNG Phase 1 project to commence commercial operations in 2027 and 2028, respectively.

PA LNG Phase 1 has definitive SPAs with an affiliate of ConocoPhillips for a 20-year term for 5 Mtpa of LNG, RWE Supply & Trading GmbH for a 15-year term for 2.25 Mtpa of LNG, INEOS for a 20-year term for approximately 1.4 Mtpa of LNG, ORLEN for a 20-year term for approximately 1 Mtpa of LNG, and ENGIE S.A. for a 15-year term for approximately 0.875 Mtpa of LNG.

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KKR Denali’s interest in the PA LNG Phase 1 project is governed by a limited liability company agreement under which (i) a subsidiary of SI Partners (a) is the managing member, (b) exclusively holds the right to make decisions with respect to certain expansions, such as the potential PA LNG Phase 2 project, (c) has certain rights to preferential distributions from specified revenues and expansion true-up payments, and (d) through a parent entity that is a subsidiary of Sempra, bears a disproportionately higher allocation of certain capital contribution commitments in certain budgetary overrun scenarios, and (ii) KKR Denali has certain investor protection voting rights.

Asset and Supply Optimization. Sempra Infrastructure has an LNG SPA through 2029 with Tangguh PSC for the supply of the equivalent of 500 MMcf of natural gas per day at a price based on the SoCal Border index for natural gas. The LNG SPA allows Tangguh PSC to divert certain LNG volumes to other global markets in exchange for payments of diversion fees. Sempra Infrastructure may also enter into short-term supply agreements to purchase LNG to be received, stored and regasified at the ECA Regas Facility for sale to other parties. Sempra Infrastructure uses the natural gas produced from this LNG to supply a contract for the sale of natural gas to the CFE at prices that are based on the SoCal Border index. If LNG volumes received from Tangguh PSC are not sufficient to satisfy the commitment to the CFE, Sempra Infrastructure may purchase natural gas in the market to satisfy such commitment.

Sempra Infrastructure purchases, transports and sells natural gas and LNG, and has customers in both the U.S. and Mexico, including the CFE. Sempra Infrastructure may also purchase natural gas from other Sempra affiliates. Natural gas purchases and transportation arrangements are substantially backed by long-term, U.S. dollar-based contracts for the sale of natural gas to third parties (both U.S. sourced and derived from imported LNG), LNG offtake and natural gas storage and pipeline capacity.

LNG Projects Under Development. Sempra Infrastructure is pursuing or evaluating the following development opportunities:

▪Cameron LNG Phase 2 project, an expansion of the Cameron LNG Phase 1 facility that would add one liquefaction train and debottlenecking capacity from the existing three trains

▪ECA LNG Phase 2 project, a large-scale natural gas liquefaction project to be located at the site of Sempra Infrastructure’s existing ECA Regas Facility in Baja California, Mexico

▪PA LNG Phase 2 project, a large-scale natural gas liquefaction project and associated infrastructure to be located adjacent to the PA LNG Phase 1 project in the vicinity of Port Arthur, Texas

▪Vista Pacifico LNG project, a mid-scale natural gas liquefaction project and associated infrastructure in the vicinity of Topolobampo in Sinaloa, Mexico

No final investment decision has been reached for any of these potential projects.

Demand and Competition. North America benefits from numerous competitive advantages as a potential supplier of LNG to world markets, including the following:

▪high levels of developed and undeveloped natural gas resources, including unconventional natural gas and oil relative to domestic consumption levels

▪flexible and mature oil and gas markets resulting in efficient unit costs of gas production

▪availability of extensive natural gas pipeline transmission systems and natural gas storage capacity with proximity to production locations

Global LNG demand and competition may limit North American LNG exports, as international liquefaction projects attempt to match North American LNG production costs and customer contractual rights such as volume and destination flexibility. North American LNG exports add market flexibility that is expected to facilitate additional growth of a global commodity market for natural gas and LNG.

Our LNG projects in development, under construction and in operation all compete globally to market and sell LNG to remarketers and end-users, including gas and electric utilities located in LNG-importing countries around the world. We compete with liquefaction projects currently operating and those under development in the global LNG market. In addition to the U.S., these competitors are located in the Middle East, Southeast Asia, Africa, South America, Australia and Europe.

Energy Networks

Sempra Infrastructure’s Energy Networks business line is comprised of a natural gas transportation and distribution network.

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Cross-Border Interconnections and In-Country Pipelines. Sempra Infrastructure develops, builds, operates and invests in systems for the receipt, transportation, compression and delivery of natural gas and ethane. At December 31, 2024, these systems consisted of 1,985 miles of natural gas transmission pipelines, 17 natural gas compression stations and 139 miles of ethane pipelines in Mexico. The design capacity of these pipeline assets is over 16,900 MMcf per day of natural gas, 204 MMcf per day of ethane gas and 106,000 barrels per day of ethane liquid. Capacity on Sempra Infrastructure’s pipelines and related assets is substantially contracted under long-term, U.S. dollar-based agreements with major industry participants such as the CFE, Centro Nacional de Control de Gas, PEMEX and other similar counterparties. See “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure” for a discussion about Sempra Infrastructure’s Sonora pipeline.

Sempra Infrastructure owns a 40-mile natural gas pipeline in south Louisiana, the Cameron Interstate Pipeline, which links the Cameron LNG Phase 1 facility in Cameron Parish in Louisiana to seven pipelines that offer access to major feed gas supply basins in Texas and the northeast, midcontinent and southeast regions of the U.S. The majority of transportation capacity on the Cameron Interstate Pipeline is under long-term transportation service agreements with shippers for delivery to the Cameron LNG Phase 1 facility.

Sempra Infrastructure is constructing the Port Arthur Pipeline Louisiana Connector, a 72-mile pipeline connecting the PA LNG Phase 1 project to Gillis, Louisiana. We expect the Port Arthur Pipeline Louisiana Connector to be ready for service ahead of the PA LNG Phase 1 project’s gas requirements.

Natural Gas Distribution. Sempra Infrastructure owns the natural gas distribution regulated utility, Ecogas, which operates in three separate distribution zones in Mexicali, Chihuahua and La Laguna-Durango, Mexico. At December 31, 2024, Ecogas had approximately 3,142 miles of distribution pipeline, and approximately 163,000 customer meters serving more than 628,000 residential, commercial and industrial consumers with sales volume of approximately 10 MMcf per day in 2024. Ecogas relies on supply and transportation services, including from Sempra Infrastructure and SoCalGas for the natural gas it distributes to its customers.

LPG Storage and Associated Systems. Sempra Infrastructure owns and operates the TDF, S. de R. L. de C. V. (TDF) pipeline system and the Guadalajara LPG terminal. At December 31, 2024, the TDF pipeline system consisted of approximately 118 miles of 12-inch diameter LPG pipeline with a design capacity of 34,000 barrels per day and associated storage and dispatch facilities. The TDF pipeline system runs from PEMEX’s Burgos facility in the Mexican state of Tamaulipas, Mexico to Sempra Infrastructure’s approximately 32,000-barrel LPG storage facility near the city of Monterrey, Mexico and is fully contracted to PEMEX on a firm basis through 2027. Sempra Infrastructure’s Guadalajara LPG terminal is an 80,000-barrel LPG storage facility near Guadalajara, Mexico, with associated loading and dispatch facilities, and serves the LPG needs of Guadalajara. The Guadalajara LPG terminal is fully contracted to PEMEX on a firm basis through 2028. Both contracts are U.S. dollar-denominated or referenced and are periodically adjusted for inflation.

Refined Products and Natural Gas Storage. Sempra Infrastructure’s refined products storage business develops, constructs and operates systems for the receipt, storage and delivery of refined products, principally gasoline, diesel and jet fuel, throughout the Mexican states of Baja California, Colima, Estado de Mexico, Puebla, Sinaloa and Veracruz for private companies, with a combined storage capacity of 4.6 million barrels fully operating as of December 31, 2024. The Topolobampo marine terminal commenced commercial operations in June 2024. Our customer contracts for our refined products storage business are structured as long-term, U.S. dollar-denominated, firm capacity storage agreements with counterparties including Marathon Petroleum Corporation, Valero Energy Corporation and PEMEX. The contracted rate under these contracts is independent from each terminal’s regulated rate as determined by the CRE.

Sempra Infrastructure is constructing Louisiana Storage, a 12.5-Bcf salt dome natural gas storage facility to support the PA LNG Phase 1 project. The construction includes an 11-mile pipeline that will connect to the Port Arthur Pipeline Louisiana Connector. We expect Louisiana Storage to be ready for service in time to support the needs of the PA LNG Phase 1 project.

Demand and Competition. Ecogas faces competition from other distributors of natural gas in each of its three distribution zones in Mexicali, Chihuahua and La Laguna-Durango, Mexico as other distributors of natural gas build or consider building natural gas distribution systems. Sempra Infrastructure’s pipeline and storage facilities businesses compete with other regulated and unregulated pipeline and storage facilities. They compete primarily on the basis of price (in terms of storage and transportation fees), available capacity and interconnections to downstream markets. The overall demand for natural gas distribution services increases during the winter months, while the overall demand for power increases during the summer months.

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Low Carbon Solutions

Sempra Infrastructure’s Low Carbon Solutions business line is focused on commercializing and deploying low carbon solutions in support of meeting the demand for lower carbon and reliable energy supply. The portfolio of resources includes renewable energy infrastructure, a natural gas-fired power plant, as well as potential hydrogen fuel production and advanced carbon capture, usage and storage technologies that are under development.

Renewable Power Generation. Sempra Infrastructure develops, builds and operates renewable energy generation facilities that have long-term PPAs to sell the electricity they generate to their customers, which are generally load-serving entities, as well as industrial and other customers. Load serving entities sell electric service to their end-users and wholesale customers upon receipt of power delivery from these energy generation facilities, while industrial and other customers consume the electricity to run their facilities. At December 31, 2024, Sempra Infrastructure had total nameplate capacity of 1,044 MW related to its operating wind and solar power generation facilities. Generation from Sempra Infrastructure’s renewable energy assets is susceptible to fluctuations in naturally occurring conditions such as wind, inclement weather and hours of sunlight. Additionally, some of these facilities are impacted by regulatory actions by the Mexican government and related litigation, which we discuss in Note 15 of the Notes to Consolidated Financial Statements, “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure.”

RENEWABLE POWER GENERATION
	Location	Contract expiration date	Nameplate capacity (MW)
Wind power generation facilities:
ESJ – first phase	Tecate, Baja California	2035	155
ESJ – second phase	Tecate, Baja California	2042	108
Ventika	Nuevo León, Mexico	2036	252
Solar power generation facilities:
Border Solar	Ciudad Juarez, Chihuahua	2032 and 2037	150
Don Diego Solar	Benjamin Hill, Sonora	2034 and 2037	125
Pima Solar	Caborca, Sonora	2038	110
Rumorosa Solar	Tecate, Baja California	2034	44
Tepezalá Solar	Aguascalientes	2034	100
Total			1,044

Natural Gas-Fired Generation. Sempra Infrastructure owns and operates the TdM power plant in the vicinity of Mexicali, Baja California, adjacent to the Mexico-U.S. border. TdM is a 625 MW natural gas-fired, combined-cycle power plant that is connected to our Gasoducto Rosarito pipeline system, which enables it to receive regasified LNG from the ECA Regas Facility as well as continental gas supplied from the U.S. on the North Baja pipeline. TdM generates revenue from selling electricity and resource adequacy to the California ISO for delivery to governmental, public utility and wholesale power marketing entities.

Low Carbon Solutions Projects. Sempra Infrastructure is constructing the Cimarrón Wind project, an approximately 320 MW wind generation facility in Baja California, Mexico. Sempra Infrastructure has a 20-year PPA with Silicon Valley Power for the long-term supply of renewable energy to the City of Santa Clara, California. Cimarrón Wind will utilize Sempra Infrastructure’s existing cross-border high voltage transmission line to interconnect and deliver clean energy to the East County substation in San Diego County. We expect the Cimarrón Wind project to begin generating energy in late 2025 and commence commercial operations in the first half of 2026.

Sempra Infrastructure is also evaluating the Hackberry Carbon Sequestration development opportunity, which is a carbon capture and sequestration project that is intended to reduce emissions at the Cameron LNG Phase 1 facility and proposed Cameron LNG Phase 2 project.

Demand and Competition. Sempra Infrastructure competes with Mexican and foreign companies for new energy infrastructure projects in Mexico. Some of its competitors (including public or state-operated companies and their affiliates) may have better access to capital or greater financial and other resources or advantages, which could give them a competitive advantage for such projects.

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Sempra Infrastructure sells power from its ESJ wind power facility into California, where renewable energy demand is affected by U.S. state mandates requiring a portion of energy to come from renewable sources. These mandates are part of California’s RPS Program. The first and second phases of ESJ, which are in operation, were certified by the CEC under the RPS Program. Certification by the CEC means that the energy produced by a facility can be counted towards the RPS Program requirements, which in turn affects the demand from California load serving entities for energy from that facility. In January 2025, the CEC approved Cimarrón Wind’s application for precertification under the RPS Program.

TdM competes daily with other generating plants that supply power into the California electricity market. Sempra Infrastructure manages commodity price risk at TdM by using a mix of day ahead sales of energy, energy spreads hedging, ancillary services, and short-term to medium-term capacity sales.

REGULATION

We discuss the material effects of compliance with all government regulations, including environmental regulations, on our capital expenditures, earnings and competitive position in “Part II – Item 7. MD&A” and Note 15 of the Notes to Consolidated Financial Statements.

Utility Regulation

California

SDG&E and SoCalGas are principally regulated at the state level by the CPUC, CEC and CARB.

The CPUC:

▪consists of five commissioners appointed by the Governor of California for staggered, six-year terms;

▪regulates, among other things, SDG&E’s and SoCalGas’ customer rates and conditions of service, sales of securities, rates of return, capital structure, rates of depreciation, and long-term resource procurement, except as described below in “U.S. Federal;”

▪has jurisdiction over the proposed construction of major new electric generation, transmission and distribution, and natural gas storage, transmission and distribution facilities in California;

▪conducts reviews and audits of utility performance and compliance with regulatory guidelines and conducts investigations related to various matters, such as safety, reliability and planning, deregulation, competition and the environment; and

▪regulates the interactions and transactions of SDG&E and SoCalGas with Sempra and other affiliates, including their marketing functions.

The CPUC also oversees and regulates other energy-related products and services, including solar and wind energy, bioenergy, alternative energy storage and other forms of renewable energy. In addition, the CPUC’s safety and enforcement role includes inspections, investigations and penalty and citation processes for safety and other violations.

The CEC publishes electric demand forecasts for the state and specific service territories. Based on these forecasts, the CEC:

▪determines the need for additional energy sources and conservation programs;

▪sponsors alternative-energy research and development projects;

▪promotes energy conservation programs to reduce demand for natural gas and electricity within California;

▪maintains a statewide plan of action in case of energy shortages; and

▪certifies power-plant sites and related facilities within California.

The CEC conducts a 20-year forecast of available supplies and prices for every market sector that consumes natural gas in California. This forecast includes resource evaluation, pipeline capacity needs, natural gas demand and wellhead prices, and transportation and distribution costs. This analysis is one of many resource materials used to support SDG&E’s and SoCalGas’ long-term investment decisions.

We discuss regulatory oversight by CARB below in “Environmental Matters – Air Quality and GHG Emissions.”

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Texas

Oncor’s and Sharyland Utilities’ rates are regulated at the state level by the PUCT and, in the case of Oncor, at the city level by certain cities. The PUCT has original jurisdiction over wholesale transmission rates and services and retail rates and services in unincorporated areas and in those municipalities that have ceded original jurisdiction to the PUCT, and has exclusive appellate jurisdiction to review the retail rates, retail services, and ordinances of municipalities. Generally, the Texas PURA prohibits the collection of any rates or charges by a public utility (as defined by PURA) that do not have the prior approval of the appropriate regulatory authority (i.e., the PUCT or the municipality with original jurisdiction).

At the state level, PURA requires utility owners or operators of electric transmission facilities to provide open-access wholesale transmission services to third parties at rates and terms that are nondiscriminatory and comparable to the rates and terms of the utility’s own use of its system. The PUCT has adopted rules implementing the state open-access requirements for all utilities that are subject to the PUCT’s jurisdiction over electric transmission services, including Oncor.

U.S. Federal

SDG&E and SoCalGas are also regulated at the federal level by the FERC, the EPA, the DOE and the DOT, and for SDG&E the NRC.

The FERC regulates SDG&E’s and SoCalGas’ interstate sale and transportation of natural gas. The FERC also regulates SDG&E’s transmission and wholesale sales of electricity in interstate commerce, transmission access, rates of return and rates of depreciation on transmission investment, electric rates involving sales for resale and the application of the uniform system of accounts. The U.S. Energy Policy Act governs procedures for requests for electric transmission service. The California IOUs’ electric transmission facilities are under the operational control of the California ISO. As member utilities, Oncor and Sharyland Utilities operate within the ERCOT market, which we discuss below. To a small degree related to limited interconnections to other markets, Oncor’s electric transmission revenues are provided under tariffs approved by the FERC.

The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities in the U.S., including SONGS, in which SDG&E owns a 20% interest, and which permanently ceased operations in 2013. The NRC and various state regulations require extensive review of these facilities’ safety, radiological and environmental aspects. We provide further discussion of SONGS matters, including the closure and decommissioning of the facility, in Note 14 of the Notes to Consolidated Financial Statements.

The EPA implements federal laws to protect human health and the environment, including federal laws on air quality, water quality, wastewater discharge, solid waste management, and hazardous waste disposal and remediation. The EPA also sets national environmental standards that state and tribal governments implement through their regulations. As a result, SDG&E, SoCalGas, Oncor and Sharyland Utilities are subject to an interrelated framework of environmental laws and regulations.

The DOT, through PHMSA, has established regulations regarding engineering standards and operating procedures, including procedures intended to manage cybersecurity risks, applicable to SDG&E’s and SoCalGas’ natural gas transmission and distribution pipelines, as well as natural gas storage facilities. The DOT has certified the CPUC to administer oversight and compliance with these regulations for the entities they regulate in California.

ERCOT Market

As member utilities, Oncor and Sharyland Utilities operate within the ERCOT market, which represents approximately 90% of the electricity consumption in Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the ISO of the interconnected transmission grid for those systems. ERCOT is subject to oversight by the PUCT and the Texas Legislature. ERCOT is responsible for ensuring reliability, adequacy and security of the electric systems, as well as nondiscriminatory access to transmission service by all wholesale market participants, in the ERCOT region. ERCOT’s membership consists of corporate and associate members, including electric cooperatives, municipal power agencies, independent generators, independent power marketers, transmission service providers, distribution service providers, independent retail electric providers and consumers.

The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of power supply across Texas’ main interconnected electric transmission grid. Oncor and Sharyland Utilities, along with other owners of electric transmission and distribution facilities in Texas, assist the ERCOT ISO in its operations. Each of these Texas utilities has planning, design, construction, operation, maintenance and security responsibility for the portion of the transmission grid and the load-serving substations it owns, primarily within its certificated distribution service area. Each participates with the ERCOT ISO and other ERCOT utilities in obtaining regulatory approvals and planning, designing, constructing and upgrading transmission lines in order to remove any existing constraints and interconnect energy generation on the ERCOT transmission grid. These transmission line projects are necessary to meet reliability needs, support energy production and increase bulk power transfer capability.

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Oncor and Sharyland Utilities are subject to reliability standards adopted and enforced by the Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with the standards of the North American Electric Reliability Corporation, including critical infrastructure protection, and ERCOT protocols.

Other U.S. State and Local Territories Regulation

SDG&E has electric franchise agreements with the two counties and the 27 cities in its electric service territory, and natural gas franchise agreements with the one county and the 18 cities in its natural gas service territory. These franchise agreements allow SDG&E to locate, operate and maintain facilities for the transmission and distribution of electricity or natural gas. Most of the franchise agreements have no expiration dates, while some have expiration dates that range from 2028 to 2041. SDG&E has electric and natural gas franchises for the City of San Diego. These franchise agreements, which went into effect in July 2021, provide SDG&E the opportunity to serve the City of San Diego for the next 20 years, consisting of 10-year agreements that will automatically renew for an additional 10 years unless the City Council voids the automatic renewal. These franchise agreements have been challenged in two lawsuits that we discuss in Note 15 of the Notes to Consolidated Financial Statements.

SoCalGas has natural gas franchise agreements with the 12 counties and the 232 cities in its service territory. These franchise agreements allow SoCalGas to locate, operate and maintain facilities for the transmission and distribution of natural gas. Most of the franchise agreements have no expiration dates, while some have expiration dates that range from 2026 to 2069. In December 2024, the Los Angeles County Board of Supervisors granted SoCalGas a new, 20-year gas pipeline franchise. The franchise consists of an initial 10-year term beginning on January 9, 2025, followed by a 10-year term that Los Angeles County has the option to terminate. Prior to the granting of the new franchise, SoCalGas continued to serve customers in the unincorporated territory of Los Angeles County in accordance with its prior franchise.

Other U.S. Regulation

The FERC regulates certain Sempra Infrastructure assets pursuant to the U.S. Federal Power Act and Natural Gas Act, which provide for FERC jurisdiction over, among other things, sales of wholesale power in interstate commerce, transportation of natural gas in interstate commerce, and siting and permitting of LNG facilities.

The FERC may regulate rates and terms of service based on a cost-of-service approach or, in geographic and product markets determined by the FERC to be sufficiently competitive, rates may be market-based. FERC-regulated rates at Sempra Infrastructure are market-based for wholesale electricity sales, cost-based for the transportation of natural gas, and market-based for the purchase and sale of LNG and natural gas.

Sempra Infrastructure’s investment in Cameron LNG JV is subject to regulations of the DOE regarding the export of LNG. Under these regulations, the DOE acts on LNG export applications to non-FTA countries after completing a public interest review that includes several criteria, including economic and environmental review of the proposed export. Sempra Infrastructure’s other potential natural gas liquefaction projects would, if completed, be subject to similar regulations.

SDG&E, SoCalGas and businesses in which Sempra Infrastructure invests are subject to the DOT rules and regulations regarding pipeline safety. PHMSA, acting through the Office of Pipeline Safety, is responsible for administering the DOT’s national regulatory program to help ensure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines, including pipelines associated with natural gas storage, and develops regulations and other approaches to risk management to help ensure safety in design, construction, testing, operation, maintenance and emergency response of pipeline facilities. PHMSA also regulates the safety of onshore LNG facilities.

SDG&E, SoCalGas and Sempra Infrastructure are also subject to regulation by the U.S. Commodity Futures Trading Commission.

Foreign Regulation

Operations and projects in our Sempra Infrastructure segment are subject to regulation by the CRE, ASEA, SENER, the Mexican Ministry of Environment and Natural Resources of Mexico (Secretaría del Medio Ambiente y Recursos Naturales), and other labor and environmental agencies of city, state and federal governments in Mexico. New energy infrastructure projects may also require a favorable opinion from Mexico’s Competition Commission (Comisión Federal de Competencia Económica) in order to be constructed and operated. Recent Mexican Constitutional reforms have proposed to transfer significant powers from the CRE to SENER; implementing legislation on these reforms is expected to be forthcoming.

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Licenses and Permits

Our utilities in California and Texas obtain numerous permits, authorizations and licenses for, as applicable, the transmission and distribution of natural gas and electricity and the operation and construction of related assets, including electric generation and natural gas storage facilities, some of which may require periodic renewal.

Sempra Infrastructure obtains numerous permits, authorizations and licenses for its electric and natural gas distribution, generation and transmission systems from the local governments where these services are provided. The permits for generation, transportation, storage and distribution operations at Sempra Infrastructure are generally for 30-year terms, with options for renewal under certain regulatory conditions. Sempra Infrastructure obtains licenses and permits for the construction, operation and expansion of LNG facilities and for the import and export of LNG and natural gas. Sempra Infrastructure also obtains licenses and permits for the construction and operation of facilities for the receipt, storage and delivery of refined products. Sempra Infrastructure obtains permits, authorizations and licenses for the construction and operation of natural gas storage facilities and pipelines, and in connection with participation in the wholesale electricity market. Most of the permits and licenses associated with Sempra Infrastructure’s construction and operations are for periods generally in alignment with the construction cycle or expected useful life of the asset and in many cases are greater than 20 years.

RATEMAKING MECHANISMS

Sempra California

General Rate Case Proceedings

A CPUC GRC proceeding is designed to set sufficient base rates to allow SDG&E and SoCalGas to recover their reasonable forecasted operating costs and to provide the opportunity to realize their authorized rates of return on their investments. The proceeding generally establishes the test year revenue requirements and provides for attrition, or annual increases in revenue requirements, for each year following the test year. Both the test year revenue requirements and attrition authorize how much SDG&E and SoCalGas can collect from their customers in base rates.

We discuss the GRC in “Part I – Item 1A. Risk Factors,” “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California” and Note 4 of the Notes to Consolidated Financial Statements.

Cost of Capital Proceedings

A CPUC cost of capital proceeding every three years determines a utility’s authorized capital structure and return on rate base, which is a weighted average of the authorized returns on debt, preferred equity and common equity (referred to as ROE), weighted on a basis consistent with the authorized capital structure. The authorized return on rate base approved by the CPUC is the rate that SDG&E and SoCalGas use to establish customer rates to finance investments in CPUC-regulated electric distribution and generation, natural gas distribution, transmission and storage assets, as well as general PP&E and information technology systems investments to support operations.

The CPUC established the CCM to apply in the interim years between required cost of capital applications and considers changes in the cost of capital based on changes in interest rates based on the applicable utility bond index published by Moody’s (the CCM benchmark) for each 12-month period ending September 30 (the measurement period). The index applicable to SDG&E and SoCalGas is based on each utility’s credit rating. The CCM benchmark rate is the basis of comparison to determine if the CCM is triggered in each measurement period, which occurs if the change in the applicable Moody’s utility bond index relative to the CCM benchmark rate is larger than plus or minus 1.00% for the measurement period. The CCM, if triggered, would automatically update the authorized cost of debt based on actual costs and update the authorized ROE upward or downward by 20% of the difference between the CCM benchmark rate and the applicable Moody’s utility bond index during the measurement period, subject to regulatory approval. Alternatively, each of SDG&E and SoCalGas is permitted to file a cost of capital application to have its cost of capital determined in lieu of the CCM in an interim year in which an extraordinary or catastrophic event materially impacts its cost of capital and affects utilities differently than the market as a whole.

We discuss the cost of capital and CCM in “Part I – Item 1A. Risk Factors,” “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California” and Note 4 of the Notes to Consolidated Financial Statements.

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Transmission Rate Cases

SDG&E files separately with the FERC for its authorized ROE on FERC-regulated electric transmission operations and assets. The proceeding establishes a ROE and a formulaic rate whereby rates are determined using (i) a base period of historical costs and a forecast of capital investments, and (ii) a true-up period, similar to balancing account treatment, that is designed to provide earnings equal to SDG&E’s actual cost of service including its authorized return on investment. SDG&E makes annual filings with the FERC to update rates for the following calendar year. SDG&E may also file for ROE incentives that might apply under FERC rules. SDG&E’s debt-to-equity ratio is set annually based on the actual ratio at the end of each year.

We discuss the latest FERC rate matters in “Part I – Item 1A. Risk Factors,” “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California” and Note 4 of the Notes to Consolidated Financial Statements.

Incentive Mechanisms

SoCalGas is subject to the GCIM and is eligible for financial awards or subject to financial penalties depending on its performance in relation to specific benchmarks. We discuss the GCIM in “Part II – Item 7. MD&A” and Note 3 of the Notes to Consolidated Financial Statements.

Other Cost-Based Regulatory Recovery

The CPUC, and the FERC as it relates to SDG&E, authorize SDG&E and SoCalGas to collect, or in the case of CPUC programmatic activities, to apply for additional, revenue requirements beyond base rates from customers for certain operating and capital related costs (depreciation, taxes and return on rate base), including for:

▪costs to purchase natural gas and electricity;

▪costs associated with administering public purpose, demand response, environmental compliance, and customer energy efficiency programs;

▪other programmatic activities, such as gas distribution, gas transmission, gas storage integrity management and wildfire mitigation; and

▪costs associated with third party liability insurance premiums.

Authorized costs are recovered as the commodity or service is delivered. To the extent authorized amounts collected vary from actual costs, the differences are generally recovered or refunded in a subsequent period based on the nature of the balancing account mechanism. In general, the revenue recognition criteria for balanced costs billed to customers are met when the costs are incurred. Because these costs are substantially recovered in rates through a balancing account mechanism, changes in these costs are reflected as changes in revenues. The CPUC and the FERC may impose various review procedures before authorizing recovery or refund of amounts accumulated for authorized programs, including limitations on the program’s total cost, revenue requirement limits or reviews of costs for reasonableness. These procedures could result in delays or disallowances of recovery from customers.

Sempra Texas Utilities

Rates and Cost Recovery

Oncor’s and Sharyland Utilities’ rates are each regulated at the state level by the PUCT and, in the case of Oncor, at the city level by certain cities, and are subject to regulatory rate-setting processes and earnings oversight. This regulatory treatment does not provide assurance as to achievement of earnings levels or recovery of actual costs. Instead, their rates are based on an analysis of each utility’s costs and capital structure in a designated test year, as reviewed and approved in regulatory proceedings. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. However, there is no assurance that the PUCT will judge all of the Texas utilities’ costs to have been prudently incurred and therefore fully recoverable. The approved levels and timing of recovery could differ significantly from requested levels and timing. There can also be no assurance that the PUCT will approve any other items requested in any rate proceeding or that the regulatory process in which rates are determined will necessarily result in rates that produce full recovery of the Texas utilities’ actual post-test year costs and/or the full return on invested capital allowed by the PUCT, particularly during periods of increased capital spending, high inflation or increases in interest rates resulting in increased costs relative to the utility’s most recent base rate review.

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PUCT rules provide that a transmission and distribution utility must file a comprehensive base rate review within four years of the last order in its most recent comprehensive rate proceeding unless an extension is otherwise approved by the PUCT. However, the PUCT or any city retaining original jurisdiction over rates may direct the utility to file a base rate review, or the utility may voluntarily file a base rate review, any time prior to that deadline. Pursuant to these rules, Oncor’s next base rate review must be filed no later than June 2027.

We discuss Oncor’s most recent comprehensive base rate proceeding in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Texas Utilities.”

Sharyland Utilities’ 2020 rate case became effective in July 2021 and remains effective until the next rate case is finalized, which we expect could be in late 2025.

In addition, PUCT rules allow Texas electric utilities providing wholesale or retail distribution service to file up to two interim rate adjustment applications per year to recover distribution-related investments placed into service between base rate review proceedings. PUCT rules also allow the Texas utilities to file up to two interim rate adjustment applications per year to reflect changes in transmission-related invested capital. These applications for interim rate adjustments between base rate reviews, known as “capital tracker” provisions, are intended to encourage transmission and distribution investments in the electric system to help ensure reliability and efficiency by helping to shorten the time period between a utility’s investment in transmission and distribution infrastructure and its ability to start recovering and earning a return on such investments. However, all investments included in a capital tracker are ultimately subject to prudence review by the PUCT in the next base rate review, after such assets are put into service.

Capital Structure and Return on Equity

In April 2023, the PUCT issued a final order in Oncor’s comprehensive base rate review that set Oncor’s authorized ROE at 9.7%, a decrease from its previously authorized ROE of 9.8%, and maintained Oncor’s authorized regulatory capital structure at 57.5% debt to 42.5% equity.

Sharyland Utilities’ PUCT-authorized ROE is 9.38% and its authorized regulatory capital structure is 60% debt to 40% equity.

Sempra Infrastructure

Ecogas’ revenues are derived from service and distribution fees charged to its customers in Mexican pesos. The price Ecogas pays to purchase natural gas, which is based on international price indices, is passed through directly to its customers. The service and distribution fees charged by Ecogas are regulated by the CRE, which performs a review of rates every five years and monitors prices charged to end-users. Ecogas’ rate case for 2021 through 2025 was approved by the CRE in December 2023. The tariffs operate under a return-on-asset-base model. In the annual tariff adjustment, rates are adjusted to account for inflation or fluctuations in exchange rates, and inflation indexing includes separate U.S. and Mexican cost components so that U.S. costs can be included in the final distribution rates.

ENVIRONMENTAL MATTERS

We discuss environmental issues affecting us in Note 15 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors.” You should read the following additional information in conjunction with those discussions.

Hazardous Substances

The CPUC’s Hazardous Waste Collaborative mechanism allows California’s IOUs to recover hazardous waste cleanup costs for certain sites, including those related to certain Superfund sites. For sites that are covered by this mechanism, SDG&E and SoCalGas are permitted to recover in rates 90% of hazardous waste cleanup costs and related third-party litigation costs, and 70% of related insurance-litigation expenses. In addition, SDG&E and SoCalGas can retain a percentage of any recoveries from insurance carriers and other third parties to offset the cleanup and associated litigation costs not recovered in rates.

We record estimated liabilities for environmental remediation when amounts are probable and estimable. In addition, we record amounts authorized to be recovered in rates under the Hazardous Waste Collaborative mechanism as regulatory assets.

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Air Quality and GHG Emissions

The natural gas and electric industries are subject to increasingly stringent air quality and GHG emissions standards. AB 32, the California Global Warming Solutions Act of 2006, assigns responsibility to CARB for monitoring and establishing policies for reducing GHG emissions. The law requires CARB to develop and adopt a comprehensive plan for achieving real, quantifiable and cost-effective GHG emissions reductions, including a statewide GHG emissions cap, mandatory reporting rules, and regulatory and market mechanisms to achieve reductions of GHG emissions. CARB is a department within the California Environmental Protection Agency, an organization that reports directly to the Governor’s Office. Sempra Infrastructure is also subject to the rules and regulations of CARB.

California requires certain electric retail sellers, including SDG&E, to deliver a significant percentage of their retail energy sales from renewable energy sources. The rules governing this requirement, administered by the CPUC and the CEC, are generally known as the RPS Program. SB 100 (enacted in 2018) and SB 1020 (enacted in 2022) require each California electric utility, including SDG&E, to procure at least 50% of its annual retail electricity delivered from renewable energy or zero-carbon sources by 2026, 60% by 2030, 90% by 2035, and 95% by 2040. SDG&E expects to be in compliance with these RPS program requirements. State law also requires California’s retail electricity supply to be met with a mix of RPS Program-eligible and zero-carbon sources by 2045 without increasing carbon emissions elsewhere in the western grid or allowing resource shuffling, and instructs the CPUC, CEC, CARB and other state agencies to incorporate this requirement into all relevant planning. In addition, AB 1279 (enacted in 2022) requires the State of California to achieve net-zero GHG emissions no later than 2045, and to achieve and maintain net negative GHG emissions thereafter. AB 1279 also directs CARB to address this goal in future scoping plans, which affect major sectors of California’s economy, including energy utilities, transportation, agriculture, construction and manufacturing. Other state climate initiatives in line with this statewide goal include executive orders requiring sales of all passenger vehicles, including SDG&E’s and SoCalGas’ light-duty fleet vehicles, to be zero-emission by 2035.

California has implemented a biomethane procurement program, whereby IOUs providing gas service in California will procure a portion of the natural gas they deliver from biomethane. The rules governing this program are administered by the CPUC under SB 1440, whereby the proportion of biomethane procured will be phased-in with a state-wide, short-term target in 2025 of 17.6 Bcf per year and a medium-term target in 2030 of 72.8 Bcf per year. SDG&E and SoCalGas are allocated 6.77% and 49.26%, respectively, of the 2025 target, and 7.60% and 52.02%, respectively, of the 2030 target. The CPUC is currently evaluating public comments to inform their review of the pending Renewable Gas Procurement Plans filed by the California gas IOUs and work towards identifying potential enhancements to the biomethane procurement program structure, including areas such as increasing market competition, reducing potential barriers for biomethane producers, streamlining procurement requirements, and improving alignment with regulatory goals.

SDG&E and SoCalGas generally recover the costs to comply with these standards in rates. We discuss GHG emissions standards, allowances and obligations and RECs in Note 1 of the Notes to Consolidated Financial Statements.

The South Coast Air Quality Management District is the air pollution control agency responsible for regulating stationary sources of air pollution in the South Coast Air Basin in Southern California. The district’s territory covers all of Orange County and the urban portions of Los Angeles, San Bernardino and Riverside counties.

Sempra continues to decarbonize its operations with an aim to have net-zero scope 1 and 2 GHG emissions by 2050 and an interim target of 50% scope 1 and 2 GHG emissions reductions by 2035 (this interim target applies to Sempra California and Sempra Infrastructure’s Mexico (non-LNG) operations and is relative to a 2019 baseline). While the company no longer has a specific goal to achieve net-zero scope 3 GHG emissions by 2050, Sempra continues to advocate for programs and initiatives that support regulatory, consumer and market demand for lower- and zero-carbon energy. Additionally, although SDG&E and SoCalGas continue to support California’s goal to achieve net-zero GHG emissions by 2045, their respective abilities to achieve their net-zero aspirations, as well as Sempra’s ability to achieve its 2035 and 2050 net-zero aspirations, will depend on the development, commercialization and regulatory acceptance of affordable lower carbon generation resources and cleaner fuels, among other factors. For a discussion of risks and uncertainties related to our net-zero and other climate aims, see “Part I – Item 1A. Risk Factors.”

With respect to our net-zero aims, even in a state of “net-zero,” GHG emissions may still be generated, but with innovation and continued development of new technology and solutions, it could allow an equal amount of carbon dioxide or its equivalent to be removed from the atmosphere, resulting in a zero increase in overall net emissions. In addition, for purposes of these net-zero aims, we expect that achievement of net-zero GHG emissions will be determined based on operations in 2050 and GHG emissions will be calculated according to widely accepted emissions reporting guidelines or mandates at that time, and our net-zero aim does not include Oncor, which sets its own goals due to certain ring-fencing measures that limit Sempra’s ability to direct the management or activities of Oncor.

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OTHER MATTERS

Information About Our Executive Officers

INFORMATION ABOUT EXECUTIVE OFFICERS
Name	Age(1)	Positions held over last five years	Time in position
Sempra:
Jeffrey W. Martin	63	President	March 2020 to present
		Chairman	December 2018 to present
		Chief Executive Officer	May 2018 to present
Karen L. Sedgwick	58	Executive Vice President and Chief Financial Officer	January 2024 to present
		Chief Administrative Officer	December 2021 to December 2023
		Chief Human Resources Officer	September 2020 to December 2023
		Senior Vice President	September 2020 to December 2021
		Chief Human Resources Officer and Chief Administrative Officer,  SDG&E	April 2019 to September 2020
Justin C. Bird	54	Executive Vice President	January 2024 to present
		Chief Executive Officer, Sempra Infrastructure	November 2021 to present
		Chief Executive Officer, Sempra LNG	April 2020 to November 2021
		President, Sempra LNG	March 2019 to April 2020
Diana L. Day	60	Chief Legal Counsel	January 2024 to present
		Deputy General Counsel	October 2022 to December 2023
		Senior Vice President, SDG&E	August 2020 to October 2022
		Chief Risk Officer, SDG&E	August 2019 to October 2022
		General Counsel, SDG&E	January 2019 to October 2022
		Vice President, SDG&E	January 2019 to August 2020
Lisa M. Larroque Alexander	51	Senior Vice President, Human Resources	January 2025 to present
		Senior Vice President, Corporate Affairs	April 2020 to present
		Vice President, Corporate Communications and Sustainability	May 2018 to April 2020
Peter R. Wall	53	Senior Vice President	April 2020 to present
		Controller and Chief Accounting Officer	May 2018 to present
		Vice President	May 2018 to April 2020

(1)    Ages are as of February 25, 2025.

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INFORMATION ABOUT EXECUTIVE OFFICERS
Name	Age(1)	Positions held over last five years	Time in position
SDG&E:
Caroline A. Winn	61	Chief Executive Officer	August 2020 to present
		Chief Operating Officer	January 2017 to July 2020
Bruce A. Folkmann(2)(3)	57	Special Projects Officer	February 2025 to present
		Chief Financial Officer	March 2015 to present
		President	August 2020 to January 2025
		Senior Vice President	August 2019 to July 2020
		Controller, Chief Accounting Officer and Treasurer	March 2015 to August 2020
Valerie A. Bille(3)	46	Vice President, Controller, Chief Accounting Officer and Treasurer	August 2020 to present
		Assistant Controller, Sempra	June 2019 to August 2020
Scott B. Crider	50	President	February 2025 to present
		Senior Vice President, External and Operations Support	June 2022 to January 2025
		Senior Vice President, Customer Services and External Affairs	June 2021 to June 2022
		Chief Customer Officer	September 2020 to June 2021
		Vice President, Customer Services	July 2016 to September 2020
Kevin C. Geraghty	59	Chief Operating Officer	June 2022 to present
		Chief Safety Officer	January 2021 to present
		Senior Vice President, Electric Operations	July 2020 to June 2022
		Chief Operating Officer and Senior Vice President, Operations, Nevada Energy, an electric and natural gas public utility in Nevada	October 2017 to May 2020
Erbin B. Keith	64	Senior Vice President and General Counsel	October 2022 to present
		Chief Risk Officer	October 2022 to May 2023
		Deputy General Counsel, Sempra	March 2019 to October 2022

(1)    Ages are as of February 25, 2025.

(2)    Mr. Folkmann will retire as of April 1, 2025.

(3)    Mr. Folkmann will relinquish and Ms. Bille will assume the role as Chief Financial Officer effective March 1, 2025.

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INFORMATION ABOUT EXECUTIVE OFFICERS
Name	Age(1)	Positions held over last five years	Time in position
SoCalGas:
Maryam S. Brown	49	Chief Executive Officer	January 2025 to present
		President	March 2019 to present
Mia L. DeMontigny	52	Senior Vice President	July 2022 to present
		Chief Financial Officer and Treasurer	June 2019 to present
		Chief Accounting Officer	June 2019 to May 2024
		Controller	June 2019 to July 2022
		Vice President	June 2019 to August 2021
David J. Barrett	60	Senior Vice President	July 2022 to present
		General Counsel	January 2019 to present
		Vice President	January 2019 to July 2022
Jimmie I. Cho(2)(3)	60	Chief Operating Officer	January 2019 to present
Sara P. Mijares	43	Chief Accounting Officer	May 2024 to present
		Assistant Treasurer	April 2023 to present
		Vice President and Controller	July 2022 to present
		Vice President of Accounting and Finance	August 2021 to July 2022
		Assistant Controller	June 2020 to July 2022
		PricewaterhouseCoopers LLP	July 2003 to January 2020

(1)    Ages are as of February 25, 2025.

(2)    Mr. Cho will retire as of March 1, 2025.

(3)    Rodger R. Schwecke, not currently an executive officer, will assume the role as Chief Operating Officer effective March 1, 2025.

Human Capital

Our ability to advance our mission to be North America’s premier energy infrastructure company largely depends on the safety, engagement, and responsible actions of our employees.

Safety is foundational at Sempra and its subsidiaries. We strive to foster a strong safety culture and reinforce this culture through various policies, programs and systems designed to mitigate the occurrence and extent of safety incidents, including, training programs, benchmarking, review and analysis of safety trends, internal compliance assessments and audits, and sharing lessons learned from safety incidents and near misses across our businesses. Our businesses also engage in safety-related scenario planning and simulation, develop and implement operational contingency plans, and review safety plans and procedures with work crews regularly. We also participate in emergency planning and preparedness in the communities we serve and train critical employees in emergency management and response each year. The SST Committee assists the Sempra board of directors in overseeing the company’s oversight programs and performance related to safety, and our executives’ annual incentive compensation is based in part on safety metrics established by the Compensation and Talent Development Committee of the board.

In addition, we strive to create a high-performing, inclusive and supportive workplace where employees of all backgrounds and experiences feel valued and respected. We invest in recruiting, developing and retaining high-performing employees who represent the communities we serve, and we provide a range of programs for employees, including internal and external mentoring and leadership training and workshops, employee resource groups, and a benefits package including wellness benefits and a tuition reimbursement program. We also invest in internal communications programs, including in-person and virtual learning and networking opportunities as well as regular executive communications to employees on topics of interest. In addition, we offer a variety of employee community service opportunities, and at our U.S. operations, we support employees’ personal volunteering and charitable giving through the charitable matching program of Sempra Foundation, which was founded and is solely funded by Sempra. Employees participate in annual ethics and compliance training, which includes a review of Sempra’s Code of Business Conduct as well as information about resources such as Sempra’s ethics and compliance helpline. We measure culture and employee engagement through a variety of channels including pulse surveys, suggestion boxes and a biannual engagement survey administered by a third party.

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The table below shows the number of employees for each of the Registrants at December 31, 2024, as well as the number of those employees represented by labor unions under various collective bargaining agreements that generally cover wages, benefits, working conditions and other terms and conditions of employment. We did not experience any major work stoppages in 2024, and we maintain constructive relations with our labor unions.

NUMBER OF EMPLOYEES
	Number of employees	Number of employees covered under collective bargaining agreements	Number of employees covered under collective bargaining agreements expiring within one year
Sempra(1)	16,773	6,335	4,895
SDG&E	4,779	1,440	—
SoCalGas	8,829	4,850	4,850

(1)    Excludes employees of equity method investees.

Labor Relations

Field, technical and most clerical employees at SoCalGas are represented by the Utility Workers Union of America or the International Chemical Workers Union Council. The collective bargaining agreement for these employees covering wages, hours, working conditions, and medical and other benefit plans was due to expire on September 30, 2024, but was extended by mutual agreement through February 7, 2025, while SoCalGas and the unions continued negotiations. Two ratification votes in late 2024 were not successful. SoCalGas is currently operating under the terms of the expired agreement while the parties continue to negotiate revised terms and seek a positive ratification vote from union members. Until a new collective bargaining agreement is ratified by employees, there could be labor disruptions, though we do not anticipate that such labor disruptions would have a material impact on service.

COMPANY WEBSITES

The Registrants’ website addresses are:

▪Sempra – www.sempra.com

▪SDG&E – www.sdge.com

▪SoCalGas – www.socalgas.com

We make available free of charge on the Sempra website, and for SDG&E and SoCalGas, via a hyperlink on their websites, annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC.

The references to our websites in this report are not active hyperlinks and the information contained on, or that can be accessed through, the websites of Sempra, SDG&E and SoCalGas or any other website referenced herein is not a part of or incorporated by reference in this report or any other document that we file with or furnish to the SEC.

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ITEM 1A. RISK FACTORS

When evaluating our company and its consolidated entities and any investment in our or their securities, you should carefully consider the following risk factors and all other information contained in this report and the other documents we file with the SEC (including those filed subsequent to this report). We also may be materially harmed by risks and uncertainties not currently known to us or that we currently consider immaterial. If any of these risks occurs, our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected, our actual results could differ materially from those expressed or implied in our forward-looking statements, and the trading prices of our securities and those of our consolidated entities could decline. These risk factors are not prioritized in order of importance or materiality, and they should be read together with the other information in this report, including in the Consolidated Financial Statements and in “Part II – Item 7. MD&A.”

RISKS RELATED TO SEMPRA

Operational and Structural Risks

Sempra’s ability to pay dividends and meet its obligations largely depends on the performance of its subsidiaries and entities accounted for as equity method investments.

We are a holding company and substantially all the assets that produce our earnings are owned by our subsidiaries or entities we do not control, including equity method investments. Our ability to pay dividends and meet our debt and other obligations largely depends on distributions from our subsidiaries and equity method investments, which in turn depend on their ability to execute their business strategies and generate cash flows in excess of their own expenditures, dividend payments to third-party owners (if any) and debt and other obligations. In addition, entities accounted for as equity method investments, which we do not control, and our subsidiaries are all separate and distinct legal entities that are not obligated to pay dividends or make loans or distributions to us and could be precluded from doing so by legislation, regulation or contractual restrictions, in times of financial distress or in other circumstances. The inability to access capital from our subsidiaries and equity method investments could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Sempra’s rights to the assets of its subsidiaries and equity method investments are structurally subordinated to the claims of each entity’s trade and other creditors. When Sempra is a creditor of any such entity, its rights as a creditor are effectively subordinated to any security interest in the entity’s assets and any indebtedness of the entity senior to that held by Sempra. In addition, Sempra may elect to make capital contributions to its subsidiaries, which are not required to be repaid and are structurally subordinated to claims by creditors of the applicable subsidiary.

Our investments in businesses we do not control expose us to risks.

We have investments in businesses we do not control or manage or in which we share control. In some cases, we engage in arrangements with or for these businesses that could expose us to risks in addition to our investment, including guarantees, indemnities and loans. For businesses we do not control, we are subject to the decisions of others, which may be adverse to our interests. When we share control of a business with other owners, any disagreements among the owners about strategy, financial, operational, transactional or other important matters could hinder the business from moving forward with key initiatives or taking other actions and could negatively affect the relationships among the owners and the efficient functioning of the business. In addition, irrespective of whether we control these businesses, we could be responsible for liabilities or losses related to these businesses or elect to make capital contributions to these businesses. Any such circumstance could materially adversely affect our results of operations, financial condition, cash flows and/or prospects. We discuss these investments in Note 5 of the Notes to Consolidated Financial Statements.

Our business could be negatively affected by activist shareholders.

We have been and may in the future be subject to activist shareholder attention. Activist shareholders may engage in proxy solicitations, advance shareholder proposals or otherwise attempt to effect changes in or assert influence on our board of directors and management. In taking these steps, activist shareholders could seek to acquire our capital stock, in spite of the provisions of our articles of incorporation and bylaws that could have the effect of delaying, deterring or preventing a change of control or other takeover of our company, even when our shareholders might consider such a change of control to be in their best interests. At certain ownership levels, these acquisitions of our common stock could threaten our ability to use some or all of our NOL or tax credit carryforwards if our corporation experiences an “ownership change” under applicable tax rules. Responding to activist

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shareholders can be costly and time-consuming and requires time and attention by our board of directors and management, diverting their attention from our business strategies.

Any actual or perceived instability in our future direction, inability to execute our strategies, or changes in our board of directors or management team arising from activist shareholder campaigns could be exploited by our competitors and/or other activist shareholders, result in the loss of business opportunities, and make it more difficult to pursue our strategic initiatives or attract and retain qualified personnel and business partners, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Financial and Capital Stock-Related Risks

Successfully completing our five-year capital expenditures plan is subject to certain risks.

The execution of our five-year capital expenditures plan may not be completed in accordance with current expectations or produce the desired results. Factors that have historically impacted and could continue to impact the amount, timing and types of capital expenditures we make include the cost and availability of financing; economic and market conditions; regulatory approvals; changes in tax law; business opportunities providing desirable rates of return; forecasts related to safety, reliability and load growth, gas system planning, and transportation electrification; safety and environmental requirements and climate-related policies; and cooperation of third-parties, including customers, partners, suppliers, lenders and others. We discuss these and other relevant factors under “Risks Related to All Sempra Businesses” below. We aim to finance our five-year capital expenditures plan in a manner that will maintain our investment-grade credit ratings and capital structure, but there can be no guarantee that we will be able to do so.

SDG&E and SoCalGas may be required to make significant expenditures before they can request rate recovery for certain capital projects. There can be no guarantee that such capital expenditures will be recoverable through rates. A significant portion of Oncor’s five-year capital expenditures plan is attributable to expected growth in ERCOT, particularly due to increased demand from large commercial and industrial customers. Changes in projected growth in ERCOT could materially impact Oncor’s capital expenditures and consequently our capital expenditures plan. Furthermore, there can be no guarantee that any of Oncor’s capital expenditures will ultimately be recoverable through rates.

The occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Settlement provisions contained in the forward sale agreements we may enter into in connection with our ATM program subject us to certain risks.

In November 2024, Sempra established an ATM program, which we discuss in Note 12 of the Notes to Consolidated Financial Statements. We are permitted to sell shares of our common stock in the ATM program pursuant to forward sale agreements, which grant each counterparty (each a forward purchaser) the right to accelerate its forward sale agreement (or, in certain cases, the portion thereof that the forward purchaser determines is affected by the relevant event) and require us to physically settle the forward sale agreement on a date specified by the forward purchaser if, subject to a prior notice requirement:

▪the forward purchaser determines in its commercially reasonable judgment that it is unable to hedge in a commercially reasonable manner its exposure to the applicable forward sale agreement because insufficient shares of our common stock are made available for borrowing by securities lenders or that, with respect to borrowing such number of shares of our common stock, it would incur a rate that is greater than the borrow cost specified in the forward sale agreement;

▪we declare any dividend, issue or distribution to existing holders of shares of our common stock that constitutes an extraordinary dividend under the forward sale agreement or is payable in (i) cash in excess of specified amounts (unless it is an extraordinary dividend), (ii) securities of another company that we acquire or own (directly or indirectly) as a result of a spin-off or similar transaction or (iii) any other type of securities (other than our common stock), rights, warrants or other assets for payment at less than the prevailing market price;

▪an event (i) is announced that, if consummated, would result in an extraordinary event (including certain mergers and tender offers, our nationalization, our insolvency and the delisting of the shares of our common stock) or (ii) occurs that would constitute a hedging disruption or change in law;

▪an ownership event (as such term is defined in the forward sale agreement) occurs; or

▪certain other events of default, termination events or other specified events occur, including, among other things, a change in law.

A forward purchaser’s decision to exercise its right to accelerate all or a portion of the settlement of its forward sale agreement and to require us to physically settle the relevant shares will be made irrespective of our interests, including our need for capital.

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In such cases, we could be required to issue and deliver shares of our common stock under the terms of the physical settlement, which would result in dilution to our EPS and may adversely affect the market price of our common stock, Series C preferred stock and any other series of preferred stock we may issue in the future.

The forward price that we expect to receive upon physical settlement of a forward sale agreement will be subject to adjustment on a daily basis based on a floating interest rate factor. If the specified daily rate is less than the applicable spread on any day, this will result in a daily reduction of the forward price. In addition, the forward price will be subject to decrease on certain dates specified in the relevant forward sale agreement by the amount per share of quarterly dividends we expect to declare on our common stock during the term of such forward sale agreement.

We will generally have the right, in lieu of physical settlement of any forward sale agreement, to elect cash or net share settlement in respect of any or all of the shares of our common stock subject to such forward sale agreement. If we elect to cash or net share settle all or any part of any forward sale agreement, we would expect to issue a substantially lower number of shares than if we settled by physical delivery, but would not receive the cash for the shares that would have otherwise been issued if we settled the entire forward sale agreement by physical delivery and, as a result, would not derive the same credit metrics benefits.

If the price of our common stock at which these purchases are made by such forward purchaser (or its affiliate) exceeds the applicable forward price, we will pay such forward purchaser an amount in cash equal to such difference (if we elect to cash settle) or we will deliver to such forward purchaser a number of shares of our common stock having a market value equal to such difference (if we elect to net share settle). Any such difference could be significant and could require us to pay a significant amount of cash or deliver a significant number of shares of our common stock to such forward purchaser.

The purchase of shares of our common stock by a forward purchaser or its affiliate to unwind the forward purchaser’s hedge position could cause the price of our common stock to increase above the price that would have prevailed in the absence of those purchases (or prevent a decrease in such price), thereby increasing the amount of cash (in the case of cash settlement) or the number of shares (in the case of net share settlement) that we would owe such forward purchaser upon settlement of the applicable forward sale agreement or decreasing the amount of cash (in the case of cash settlement) or the number of shares (in the case of net share settlement) that such forward purchaser would owe us upon settlement of the applicable forward sale agreement.

The economic interest, voting rights and market value of our outstanding common and preferred stock may be adversely affected by any additional equity securities we may issue.

At February 19, 2025, we had 651,457,249 shares of our common stock and 900,000 shares of our non-convertible series C preferred stock outstanding. Our businesses have substantial capital needs, and we may seek to raise capital by issuing additional equity, including in our ATM program, or convertible debt securities in potentially significant amounts depending in part on the prevailing market price of our common stock, which at times experiences substantial volatility. Any future issuance of equity or convertible debt securities may materially dilute the voting rights and economic interests of holders of our outstanding common and preferred stock and materially adversely affect the trading price of our common and preferred stock.

The dividend requirements of our preferred stock subject us to risks.

Any failure to pay scheduled dividends on our series C preferred stock when due would have a material adverse impact on the market price of our securities and would prohibit us, under the terms of the series C preferred stock, from paying cash dividends on or repurchasing shares of our common stock (subject to limited exceptions) until we have paid all accumulated and unpaid dividends on the series C preferred stock. Additionally, the terms of the series C preferred stock generally provide that if dividends on any shares of the preferred stock have not been declared and paid or have been declared but not paid for three or more semi-annual dividend periods, the holders of the preferred stock would be entitled to elect two additional members to our board of directors, subject to certain terms and limitations.

RISKS RELATED TO ALL SEMPRA BUSINESSES

Operational Risks

Our businesses are subject to risks arising from their infrastructure and systems that support this infrastructure.

Our facilities and the systems that interconnect and/or manage them are subject to risks of, among other things, equipment or process failures due to aging or degrading infrastructure or otherwise; human error; loss or outage of a key technology platform or system; shortages of or delays in obtaining equipment, materials, commodities or labor, which have been and may in the future be

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exacerbated by supply chain and gas transportation capacity constraints, tight labor markets, and cost increases due to inflationary pressures, tariffs or otherwise, that may not be recoverable in a timely manner or at all; operational restrictions resulting from environmental requirements or governmental interventions or permitting delays; inability to enter into, maintain, extend or replace long-term supply or transportation contracts; and performance below expected levels. Our businesses undertake capital investment projects to construct, replace, operate, maintain and upgrade facilities and systems, but such projects may not be completed or effective at managing these risks and involve significant costs that may not be recoverable. We often rely on third parties, including contractors, to perform work related to these projects and other maintenance activities, which may subject us to liability for safety issues and the quality of work performed. Because some of our facilities are interconnected with those of third parties, including customer-side-of-meter facilities, natural gas pipelines and power generation facilities that produce most of the power we distribute, the operation of our facilities could also be materially adversely affected by these or similar risks to such third-party systems, which may be unanticipated or uncontrollable by us.

Additional risks associated with our ability to safely and reliably construct, replace, operate, maintain and upgrade facilities and systems, which may be beyond our control, include:

▪failure to meet customer demand for electricity and/or natural gas, including electric or gas outages

▪gas surges into homes or other properties

▪release of hazardous or toxic substances, including gas leaks

▪other incidents impacting the health, safety, or security of employees, contractors, the public or our infrastructure

▪failure to respond effectively to catastrophic events

The occurrence of any of these events could affect supply and demand for electricity, natural gas or other forms of energy, cause unplanned outages, damage our assets and/or operations or those of third parties on which our businesses rely, damage property owned by customers or others, and cause personal injury or death. In addition, if we are unable to defend and retain title to the properties we own or obtain or retain rights to construct and operate on the properties we do not own in a timely manner, on reasonable terms or at all, we could lose our rights to occupy and use these properties and related facilities, which could prevent, limit or delay existing or proposed operations or projects, increase our costs, and result in breaches of permits or contracts and related legal costs, impairments, fines or penalties. Any such outcome could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We face risks related to severe weather, natural disasters, physical attacks and other similar events.

Our facilities and infrastructure may be damaged as a result of physical risks, such as extreme temperatures, storms, droughts and other severe weather; natural disasters, including wildfires (such as the LA Fires), land movement, earthquakes, and solar flares; climate-related conditions, including sea level rise and coastal erosion; accidents, including explosions and excavation damage to pipelines; or acts of terrorism, war, or criminality. Because we are in the business of using, storing, transporting and disposing of highly flammable, explosive and radioactive materials and operating highly energized equipment, the risks such incidents pose to our facilities and infrastructure, as well as to the surrounding communities for which we could be liable, are substantially greater than the potential risks to a typical business.

Such incidents could result in operational disruptions, electric or gas outages, property damage, personal injury or death and could cause secondary incidents that also may have these or other negative effects, such as fires; leaks or spills of gases, natural gas odorant or radioactive material; damage to natural resources; or other impacts to affected communities. Any of these occurrences could decrease revenues and earnings and/or increase costs, including maintenance costs or restoration expenses, amounts associated with claims against us, and regulatory fines, penalties and disallowances. In some cases, we may be liable for damages even though we are not at fault, such as when the doctrine of inverse condemnation applies, which we discuss below under “Risks Related to Sempra California – Operational Risks.” For our regulated utilities, these costs may not be recoverable in rates or recovery may be insufficient or delayed. Insurance coverage for these costs may continue to increase or become prohibitively expensive, be disputed by insurers, or become unavailable for certain of these risks or at adequate levels or in certain geographic locations, and any insurance proceeds may be insufficient to cover our losses or liabilities due to limitations, exclusions, high deductibles, failure to comply with procedural requirements or other factors. We discuss the risks related to insurance for wildfire liabilities below under “Risks Related to Sempra California — Operational Risks.” Such incidents that do not directly affect our facilities may impact our business partners, supply chains and transportation and communication channels, which could negatively affect our ability to operate. Moreover, weather-related incidents have become more prevalent, unpredictable and severe due to climate change or other factors. As a result, these incidents could have a greater impact on our businesses than currently anticipated and, for our regulated utilities, rates may not be adequately or timely adjusted to reflect any such increased impact. Any such outcome could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

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We face evolving cybersecurity and technology resiliency risks associated with the energy grid, pipelines, storage and other infrastructure as well as the collection of personal, sensitive and confidential information.

Our significant use of and reliance on complex technologies and information systems in our operations, including our increasing deployment of new technologies, such as advanced forms of automation and artificial intelligence, and virtualization of many business activities, and our collection and retention of personal, sensitive and confidential information, represent large-scale opportunities for attacks on, vulnerabilities in or other failures of our information systems, information and energy grid and infrastructure. Our digitalization and grid modernization efforts, including the networking of operational technology assets such as substations, continue to increase the potential vulnerabilities and points of failure in our information systems. We are also at risk of attacks on, vulnerabilities in or other failures of third-party vendors’ and/or regulators’ technologies and systems, depending on the level of access these vendors and agencies have to our information and systems. Viruses, ransomware, malware and other forms of cyber-attacks targeting utility systems and other energy infrastructure are continuously increasing in sophistication, magnitude and frequency, may not be recognized until launched against a target and may further escalate during periods of heightened geopolitical tensions. Accordingly, we may be unable to anticipate these techniques or to implement adequate preventative measures, making it impossible for us to eliminate this risk.

Our businesses also face challenges related to data governance, including the need to manage and secure large volumes of electronic data with the aim to meet regulatory requirements and create a foundation for the potential use of artificial intelligence tools. SDG&E and SoCalGas are increasingly required to disclose large amounts of data (including customer personal information and energy use data) to support state energy initiatives, increasing the risks of inadvertent disclosure or unauthorized access of sensitive information. Moreover, all our businesses operating in California (and in other states and countries that have similar laws) are subject to enhanced state privacy laws, which require companies that collect information about California residents to, among other things, disclose their data collection, use and sharing practices; allow consumers to opt out of certain data sharing with third parties; and assume liability for unauthorized disclosure of certain highly sensitive personal information.

Although we make significant investments in risk management, technology resiliency and information security measures for the protection of our systems and data, these measures could be insufficient or otherwise fail, particularly against attacks involving sophisticated adversaries, including nation-state actors, or outages involving key technology vendors. The costs and operational consequences of implementing, maintaining and enhancing these measures are significant and expected to increase to address evolving cyber risks. We often rely on third-party vendors to deploy new technologies and maintain and update our systems (including providing security updates), and these third parties may not have adequate risk management, technology resiliency and information security measures with respect to their systems or may fail to timely provide and install software updates. Although we have not experienced a material breach of our information systems or data, we and some of our vendors have been and will likely continue to be subject to breaches of and attempts to gain unauthorized access to our systems or data or efforts to otherwise disrupt our operations. Any actual or perceived noncompliance with applicable data privacy and security laws or any incidents impacting our or our vendors’ information systems; the integrity of the energy grid, our pipelines or our distribution, storage and other infrastructure; or our personal, sensitive and confidential information could result in disruptions to our business operations, regulatory compliance failures, inability to produce accurate and timely financial statements, energy delivery failures, financial and reputational loss, litigation, violations of applicable laws and fines or penalties, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. Although Sempra currently maintains cyber liability insurance, this insurance is limited in scope and subject to exceptions, conditions and coverage limitations and may not cover the costs associated with a cybersecurity incident, and there is no guarantee that the insurance we currently maintain will continue to be available at rates we believe are reasonable.

We actively seek opportunities in the market through acquisitions, partnerships, JVs and divestitures.

We diligently analyze the financial viability of each acquisition, divestiture, partnership and JV we pursue. However, our diligence may prove to be insufficient and there could be latent or unforeseen defects. In addition, we may not realize all the anticipated benefits from future acquisitions, divestitures, partnerships or JVs for various reasons, including difficulties integrating or separating operations and personnel effectively or in a timely manner, higher or unexpected transaction or operating costs, unknown liabilities, and fluctuations in markets. Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

We face risks related to increasing activities and projects intended to advance new energy technologies.

We regularly participate in research, development and demonstration projects and other activities designed to develop new technologies in the energy space, including those related to hydrogen, liquefaction, energy storage, microgrids, carbon sequestration, and grid modernization. These activities and projects involve significant employee time, as well as substantial capital resources that may not be recoverable in rates or, with respect to our businesses that are not regulated utilities, may not be

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able to be passed through to customers. We have sought and continue to seek a variety of federal and state funding opportunities, such as government incentives and subsidies under the IRA, for these activities and projects. These efforts can involve significant employee resources and increased compliance requirements and have not always been successful in securing funding on acceptable terms or at all. In some cases, applicable compliance requirements may cost more than the potential funding opportunity, limiting our ability to pursue available funding. In addition, the timing to complete these activities and projects is inherently uncertain and may require significantly more resources than we initially anticipate. Moreover, many of these technologies are in the early stage of development and may not prove economically and technically feasible or be accepted by regulators, and the applicable activities and projects may not be completed. If any of these circumstances occurs, we may not receive an adequate or any return on our investment in these activities and our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.

The operation of our facilities depends on good labor relations with our employees and our ability to attract and retain qualified personnel.

Our businesses depend on recruiting, developing and retaining qualified personnel. Several of our businesses have in place collective bargaining agreements with different labor unions, which are generally negotiated on a company-by-company basis. At December 31, 2024, employees covered under collective bargaining agreements were 38%, 30% and 55%, respectively, of Sempra’s, SDG&E’s and SoCalGas’ workforce, of which the collective bargaining agreements covering 29%, 0% and 55% of employees, respectively, expire within one year (and in the case of SoCalGas, the collective bargaining agreement expired in February 2025). Any prolonged negotiation or failure to reach an agreement on these labor contracts as they are up for renewal could result in work stoppages or other labor disruptions. For SoCalGas, negotiations for a new collective bargaining agreement are presently ongoing. Until a new collective bargaining agreement is ratified by employees, there could be labor disruptions. Additionally, we have faced a shortage of experienced and qualified personnel in certain specialty operational positions and could experience disruptions from recruiting or retention challenges for personnel in those positions. Any labor disruption, negotiated wage or benefit increases or other challenges, whether due to union activities, employee turnover, labor shortages or otherwise, could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Our businesses depend on the performance of counterparties.

Our businesses depend on the performance of business partners, customers, suppliers, contractors, and other counterparties under contractual and other arrangements to provide, among other things, services, equipment, or commodities. If they fail to perform their obligations in accordance with these arrangements or elect to exercise their early termination rights, we may be unable to meet our obligations and may be required to enter into alternative arrangements or honor our underlying commitments at then-current market prices, which may result in losses or delays or other operational disruptions. Any efforts to enforce the terms of these arrangements through legal or other means could involve significant time and costs and would be unpredictable and subject to failure. In addition, many of these arrangements and relationships with counterparties are important for the development, construction and operation of our projects and growth of our businesses. We also may not be able to secure replacement agreements with other counterparties on favorable terms, in a timely manner or at all if any of these arrangements terminate. Further, we often face counterparty credit risk with respect to customers, suppliers, and other counterparties and, although we perform credit analyses prior to extending credit or entering into transactions with such counterparties, we may not be able to collect the amounts owed to us, which could be significant and present an increased risk for our long-term supply, sales and capacity contracts. Volatility and disruptions in capital and credit markets could have a negative impact on our counterparties and their ability to meet their obligations. Sempra Infrastructure also faces risks related to doing business with PEMEX and the CFE, which are Mexican state-owned enterprises, including their financial solvency and regulation by the Mexican government and the risk that they fail to meet their respective contractual obligations, among others. Any delay or default in payment of our counterparties’ financial obligations could result in our recording of a provision for credit losses on past due receivable balances and lower revenues, as was the case in 2023 and 2024 for a customer at Sempra Infrastructure. The failure of any of our counterparties to perform in accordance with their arrangements with us could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

In addition, Sempra Infrastructure’s ECA Regas Facility has long-term capacity agreements with a limited number of counterparties and also enters into short-term and/or long-term supply agreements to purchase LNG to be received, stored and regasified for sale to other parties. Cameron LNG JV has long-term liquefaction and regasification tolling agreements with three counterparties that collectively subscribe for the full nameplate capacity of the Cameron LNG Phase 1 facility, and long-term sale and purchase agreements are in place for the expected capacity at the ECA LNG Phase 1 and PA LNG Phase 1 projects under construction. The long-term nature of these agreements and the small number of customers at each of these facilities exposes us to risks, including increased risk if these counterparties fail to meet their contractual obligations on a timely basis, increased credit risks, and risks associated with our relationships with these counterparties, including increased impacts of disputes or other similar

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issues which we have experienced in the past. Any such issues that arise in the future with respect to our long-term contracts could lead to significant legal and other costs, result in cancelation of certain key contracts or otherwise adversely affect our relationships with long-term customers, suppliers or partners, and could negatively impact the reliability of revenues from the applicable projects and the prospects for any implicated development projects. Any such event could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Sempra Infrastructure’s obligations and those of its counterparties, such as its LNG customers, are contractually subject to suspension or termination for force majeure events, which generally are beyond the control of the parties. Force majeure declarations may also have attendant negative consequences, or loss or deferral of revenue arising from non-deliveries of natural gas from suppliers or LNG to customers in certain circumstances. Also, certain force majeure events may impact the contractors constructing Sempra Infrastructure’s projects, which may result in delays or increased costs. Sempra Infrastructure may have limited remedies available for certain failures to perform, including limitations on damages that may prohibit recovery of costs incurred for any breach of an agreement. Any such occurrence could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Sempra Infrastructure engages in JVs and invests in companies in which other equity partners have or share with us control over the applicable project or investment. Sempra Texas also invests in companies it does not control or manage. We discuss the risks related to such arrangements above under “Risks Related to Sempra – Operational and Structural Risks.”

Financial Risks

Our debt service obligations expose us to risks and could require additional equity securities issuances by Sempra or sales of equity interests in subsidiaries or projects under development.

We have significant debt service obligations and an ongoing need for significant amounts of additional capital, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects by, among other things:

▪making it more difficult and costly to service, pay or refinance debts as they come due, particularly when interest rates increase or economic or industry conditions are otherwise unfavorable

▪limiting flexibility to pursue strategic opportunities or react to business developments or industry changes

▪causing lenders to require materially adverse terms for new debt, such as restrictions on uses of proceeds, limitations on incurring additional debt, paying dividends, repurchasing stock, or receiving distributions from subsidiaries or equity method investments and the creation of liens

In January 2025, S&P revised Sempra’s outlook to negative from stable and downgraded SoCalGas’ issuer credit rating to A- from A. Sempra aims to maintain or improve its credit ratings, but we may not be able to do so. To maintain these credit ratings, we may seek to reduce our outstanding indebtedness or our need for additional indebtedness by reducing or postponing discretionary, non-safety related capital expenditures or investments in new businesses. Additionally, we may issue equity securities, including in our ATM program (such as our November 2024 forward sale agreement under the ATM program for the sale of 2,909,274 shares), or sell equity interests in our subsidiaries or development projects. We may not be able to complete any such equity sales on acceptable terms or at all, and any new equity issued by Sempra may dilute the voting rights and economic interests of Sempra’s existing equity holders. Any such outcome could have a material adverse effect on Sempra’s results of operations, financial condition, cash flows and/or prospects.

The availability and cost of debt or equity financing could be negatively affected by market and economic conditions and other factors.

Our businesses are capital-intensive, with significant and increasing capital spending expected in future periods. In general, we rely on long-term debt to fund a significant portion of our capital expenditures and repay or refinance outstanding debt, and we rely on short-term debt to fund a significant portion of day-to-day operations. Sempra has also raised and may continue to seek capital by issuing equity, including in our ATM program, or selling equity interests in our subsidiaries or investments.

Limitations on the availability of credit, increases in interest rates or credit spreads due to inflation or otherwise or other negative effects on the terms of any financing we pursue could cause us to fund operations and capital expenditures at a higher cost or fail to raise our targeted amount of funds, which could negatively impact our ability to meet contractual and other commitments, progress development projects, make non-safety related capital expenditures and effectively sustain operations. Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

In addition to market and economic conditions, factors that can affect the availability and cost of capital include:

▪adverse changes to laws and regulations, including recent and proposed changes to energy market regulation in Mexico

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▪for Sempra and SDG&E, risks related to California wildfires

▪for Sempra, SDG&E and SoCalGas, any deterioration of or uncertainty in the political or regulatory environment for local natural gas distribution companies operating in California

▪credit ratings downgrades, such as S&P’s January 2025 actions that revised Sempra’s outlook to negative from stable and downgraded SoCalGas’ issuer credit rating to A- from A.

Credit rating agencies may downgrade our credit ratings or place them on negative outlook.

Credit rating agencies routinely evaluate Sempra, SDG&E, SoCalGas, SI Partners and certain of our other businesses whose ratings are based on several factors, including the factors described below and, generally, the ability to generate cash flows; terms and levels of indebtedness, including the credit rating agencies’ treatment of certain types of indebtedness, such as subordinated indebtedness which is given partial equity credit but carries a higher interest rate than comparable senior indebtedness; overall financial strength; specific transactions or events, such as share repurchases and significant litigation; the status of certain capital projects, including our LNG projects; and general economic and industry conditions. These credit ratings could be downgraded or subject to other negative rating actions at any time, such as S&P’s January 2025 actions that revised Sempra’s outlook to negative from stable and downgraded SoCalGas’ issuer credit rating to A- from A. We discuss these credit ratings in “Part II – Item 7. MD&A – Capital Resources and Liquidity.”

For Sempra, the Rating Agencies have noted that the following events, among others, could lead to negative ratings actions:

▪expansion of natural gas liquefaction projects or other unregulated businesses in a manner inconsistent with its present level of credit quality

▪the PA LNG Phase 1 project experiences higher construction costs

▪Sempra’s consolidated financial measures consistently weaken, or it fails to meet certain financial credit metrics

▪catastrophic wildfires caused by SDG&E or by any California electric IOUs that participate in the Wildfire Fund, which could exhaust the fund earlier than expected

▪a ratings downgrade at SDG&E, SoCalGas, Oncor and/or SI Partners

For SDG&E, the Rating Agencies have noted that the following events, among others, could lead to negative ratings actions:

▪catastrophic wildfires caused by SDG&E or by any California electric IOUs that participate in the Wildfire Fund, which could exhaust the fund earlier than expected

▪a consistent weakening of SDG&E’s financial metrics, or it fails to meet certain financial credit metrics

▪a deterioration in the regulatory environment, including credit negative outcomes of its pending regulatory proceedings

▪a ratings downgrade at Sempra

For SoCalGas, the Rating Agencies have noted that the following events, among others, could lead to negative ratings actions:

▪SoCalGas’ financial measures consistently weaken, or it fails to meet certain financial credit metrics

▪SoCalGas experiences increased business risk due to a deterioration in the regulatory environment, including credit negative outcomes of its pending regulatory proceedings or elevated risk concerning its natural gas utility business

▪a ratings downgrade at Sempra

For SI Partners, the Rating Agencies have noted that the following events, among others, could lead to negative ratings actions:

▪SI Partners’ failure to meet certain financial credit metrics

▪a deterioration in SI Partners’ business risk profile, including incremental construction risk or adverse changes in the operating environment in Mexico

▪the PA LNG Phase 1 project experiences challenges or delays in construction that have an adverse financial impact on SI Partners

▪a ratings downgrade at Sempra, IEnova, Cameron LNG, LLC and/or Port Arthur LNG, LLC

A downgrade of any of our businesses’ credit ratings or ratings outlooks, as well as the reasons for such downgrades, could materially adversely affect the interest rates at which borrowings can be made and debt securities issued and the various fees on our credit facilities. This could make it more costly to borrow money, issue securities and/or raise other types of capital, any of which could reduce our ability to meet our debt obligations and contractual commitments and, in the case of SDG&E and SoCalGas, increase customer rates, and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

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We do not fully hedge our assets or contract positions against changes in commodity prices or interest rates, and for positions that are hedged, our hedging mechanisms may not mitigate our risk or reduce our losses as intended.

We use forward contracts, futures, financial swaps and/or options, among other mechanisms, to hedge a portion of our known or anticipated purchase and sale commitments, inventories of natural gas and LNG, natural gas storage and pipeline capacity and electric generation capacity in an effort to reduce our, and for SDG&E and SoCalGas, customers’ financial exposure related to commodity price fluctuations. In addition, we have used and may continue to use similar financial instruments to hedge against changes in interest rates. The extent to which we hedge our positions varies over time. Certain derivative instruments are recorded at fair value through earnings to reflect movements in the price of the derivative, which has recently and could in the future create volatility in our earnings. The effect of such commodity derivative instruments for SDG&E and SoCalGas are passed through to customers in rates without markup. To the extent we have unhedged positions, or if any hedging counterparty fails to fulfill its contractual obligations or if our hedging strategies do not work as intended, fluctuating commodity prices and interest rates could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Risk management procedures may not prevent or mitigate losses.

Although we have risk management and control systems designed to quantify and manage risk, these systems may not prevent material losses. Risk management procedures may not always be followed as intended or function as expected. In addition, daily VaR and loss limits, which are primarily based on historic price movements and which we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” may not protect us from losses if prices significantly or persistently deviate from historic prices. As a result of these and other factors, our risk management procedures and systems may not prevent or mitigate losses that could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

An impairment of our goodwill or long-lived assets could result in a material charge to earnings.

We test long-lived assets, including equity method investments, for recoverability when events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of the assets. We test goodwill for impairment annually or when events or changes in circumstances necessitate a valuation. We could experience such an event or change in circumstances from, among other things, (i) an inability to operate our existing facilities, (ii) an inability to collect from customers, (iii) changes to laws or regulations or other circumstances affecting the energy sector or our assets in Mexico, (iv) adverse rulings in lawsuits, binding arbitrations, regulatory proceedings, audits and other proceedings materially impacting our businesses, including our equity method investments such as Oncor Holdings and Cameron LNG JV, and (v) more generally any loss of permits or approvals that requires us to adjust or cease certain operations and any failure to complete or receive an adequate return on our investments in capital projects. A material charge to earnings from an impairment loss could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Market performance or changes in other assumptions could require unplanned contributions to pension and PBOP plans.

Sempra, SDG&E and SoCalGas provide defined benefit pension and PBOP plans to eligible employees and retirees. The cost of providing these benefits is affected by many factors, including the market value of plan assets and the other factors described in Note 8 of the Notes to Consolidated Financial Statements and “Part II – Item 7. MD&A – Capital Resources and Liquidity.” A decline in the market value of plan assets or an adverse change in any of these other factors could cause a material increase in our funding obligations for these plans, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

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Legal and Regulatory Risks

We face risks related to failures and delays in obtaining and maintaining permits, licenses, franchises and other approvals required by our businesses.

The industries in which we operate are subject to extensive regulation, and our businesses require numerous permits, licenses, rights-of-way, franchises, certificates and other approvals from federal, state, local and foreign governmental agencies. These approvals may not be granted in a timely manner (including due to potential staffing issues at U.S. regulatory agencies) or at all or may be modified, rescinded or fail to be extended for a variety of reasons, including due to legal or regulatory changes or political considerations. The City of San Diego is studying the feasibility of municipalization as a potential alternative to SDG&E’s existing electric franchise agreement, and various aspects of SDG&E’s natural gas and electric franchise agreements have also been challenged in two lawsuits that we discuss in Note 15 of the Notes to the Consolidated Financial Statements. At Sempra Infrastructure, amendments to Mexico’s Constitution and to Mexico’s Electricity Industry Law have the potential to increase government control and participation in the energy sector and may require the CRE to revoke Sempra Infrastructure’s self-supply permits deemed improperly obtained under a legal standard that is ambiguous and not well defined under the law. Obtaining or maintaining required approvals could result in higher costs or the imposition of conditions or restrictions on our operations. Further, noncompliance by us or certain of our customers with the terms of these approvals could result in their modification, suspension or rescission and subject us to lost revenue, fines and penalties. If any of these approvals are suspended, rescinded or otherwise terminated or modified in a manner that makes our continued operation of the applicable business prohibitively expensive or otherwise impracticable, we may be required to adjust or temporarily or permanently cease certain of our operations, sell the associated assets or remove them from service and/or construct new assets intended to bypass the impacted area, in which case we may lose some of our rate base or revenue-generating assets, our development projects may be negatively affected and we may incur impairment charges or other costs that may not be recoverable. The occurrence of any of these events could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

From time to time, we invest funds in projects prior to receiving all regulatory approvals. We may be unable to recover any or all amounts invested in such projects if:

▪there is a delay in obtaining these approvals

▪any approval is conditioned on changes or other requirements that increase costs or impose restrictions on our existing or planned operations

▪we fail to obtain or maintain these approvals or comply with them or other applicable laws or regulations

▪we are involved in litigation that adversely impacts any approval or rights to the applicable property or assets

▪management decides not to proceed with a project

Our inability to recover funds invested in these projects could materially increase our costs, result in material impairments, and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

We face risks related to environmental and climate change regulation and the costs of the energy transition.

The impacts from the mitigation of climate change and related regulations may increase the costs we incur to procure and transmit energy and provide other services. The changes in costs and preferences for lower carbon and renewable energy sources may impact the demand for, consumption of, and type of energy we transmit and distribute.

Environmental and Climate Change Regulation

We are subject to extensive federal, state, regional, local and foreign statutes, orders, rules and regulations relating to climate change and environmental protection. To comply with these requirements, we must expend significant capital and employee resources on environmental monitoring, surveillance and other measures to track performance; acquisition and installation of pollution control equipment; mitigation efforts; and emissions fees, which could increase as a result of various factors we may not control, including changing laws and regulations, increased readiness and enforcement activities, delays in the renewal and issuance of permits, and changes to the mix of energy we transmit and distribute. In addition, we are generally responsible for hazardous substances and other contamination on and the conditions of our projects and properties, regardless of when these conditions arose and whether they are known or unknown. We have been and may in the future be required to pay environmental remediation costs at former facilities and off-site waste disposal sites where any of our businesses is identified as a PRP under federal, state and local environmental laws. For our regulated utilities, some or all of these costs may not be recoverable in rates. Failure to comply with environmental laws and regulations may subject us to fines and penalties, including criminal penalties in some cases, and/or curtailment of our operations. Moreover, increasing international, national, regional, state and local environmental concerns and related changes to applicable legal and regulatory frameworks, such as requirements for increased monitoring and surveillance, disclosures on environmental performance, pollution monitoring and control equipment, safety

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practices, emissions fees, taxes, penalties or other obligations or restrictions, may have material negative effects on our operations, costs, corporate planning, and the scope and economics of proposed infrastructure projects or other capital expenditures. Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

In particular, legislation and regulation designed to reduce GHG emissions and mitigate climate change are proliferating, as we discuss in “Part I — Item 1. Environmental Matters.” California’s goals are facing cost pressures and may experience delays or other challenges that could cause the state to modify its laws and rules, resulting in significant uncertainty. These or other similar laws and rules may materially restrict our operations, negatively impact demand for our services and/or the energy we transmit and distribute, limit development opportunities, force costly or otherwise burdensome changes to our operations, negatively impact customer affordability, or otherwise materially adversely affect us.

Additionally, the SEC’s final rules on climate-related disclosures and California laws requiring expansive disclosures on GHG emissions and other environmental measures, targets and claims could subject us to liability for these disclosures as well as significant compliance costs and could have other consequences that may be difficult to predict, including negative sentiment from current and potential investors, regulators or other groups. These new disclosure requirements may use different reporting frameworks and methodologies, such as reporting boundaries, which may further increase compliance costs and the risk of compliance failures and may create confusion for stakeholders. Moreover, these disclosure requirements could increase the risk that we become subject to climate change lawsuits. Defense costs associated with such litigation could be significant, and any adverse outcome could require substantial capital expenditures or payment of substantial penalties or damages. Although these new disclosure requirements are subject to challenges in pending lawsuits and may change as a result of further agency action, any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

Other Energy Transition Risks

The energy transition in California and elsewhere, including decarbonization goals, has introduced uncertainty in long-term investor support, leading some to reduce investment in or divest from our sector. Maintaining investor confidence and attracting capital at a competitive cost will depend, in part, on demonstrating our ability to address material business risks related to climate and our efforts to help achieve the goals of our consumers and the markets and jurisdictions where we operate. In an effort to maintain a sustainable and durable business risk profile and continue to focus on value creation, Sempra has evaluated and updated its climate aspirations to reflect the changing policy, regulatory, commercial and technological landscape, including stakeholders’ evolving focus on reliability, resiliency and affordability and the pace and impact of climate and other public policies. Following this evaluation, Sempra now aims to have net-zero scope 1 and 2 GHG emissions by 2050, with an interim target of 50% scope 1 and 2 GHG emissions reductions by 2035 (this interim target applies to Sempra California and Sempra Infrastructure’s Mexico (non-LNG) operations and is relative to a 2019 baseline). While the company no longer has a specific goal to achieve net-zero scope 3 GHG emissions by 2050, the capabilities we are developing through our energy transition action plan could also support the reduction of scope 3 GHG emissions and help meet regulatory, consumer and market demand for lower- and zero-carbon energy. Sempra’s, SDG&E’s and SoCalGas’ abilities to advance their respective net-zero and other climate objectives will depend on many factors, some of which we do not control, including supportive federal and state energy laws, policies, incentives, tax credits and regulatory decisions; cost and affordability considerations; development, commercialization and regulatory acceptance of alternative and lower-carbon energy sources, including cleaner fuels; successful research and development efforts focused on lower carbon technologies that are economically and technically feasible; cooperation from our partners, financing sources and commercial counterparties; customer participation in conservation and energy efficiency programs; our ability to execute our planned investments in our infrastructure; and consumers’ decisions and preferences. In addition, forecasting to 2035, 2045 and 2050 is inherently speculative without knowing the trajectory of the energy transition. As a result, although we are dedicated to progress on our climate aims and are continuing to develop capabilities designed to reduce GHG emissions from our own operations as well as to support consumers’ and markets’ own climate goals, we may not be successful in achieving these objectives.

We will need to continue to expend capital and employee resources to develop and deploy new technologies and modernize grid systems to meet the demand for lower carbon and reliable energy in California and elsewhere and achieve our climate aspirations and those mandated by applicable authorities, which may not be recoverable in rates or, with respect to our businesses that are not regulated utilities, may not be able to be passed through to customers. Even if such costs are recoverable, these costs, coupled with necessary safety and reliability investments, may negatively impact the affordability of SDG&E’s and SoCalGas’ customer rates and, for our businesses that are not regulated utilities, may cause costs to increase to levels that reduce customer demand and growth. SDG&E and SoCalGas, as well as any of our other businesses affected by GHG emissions reduction and mitigation and renewable energy mandates, may also be subject to fines and penalties if mandated goals are not met, and all our businesses could suffer difficulties attracting investors and business partners, reputational harm and other negative effects if we do not meet or if

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we further modify our GHG emissions reduction aims or there are negative views about our environmental disclosures or practices generally.

We develop our capital expenditure plans based on forecasts as well as regulatory and compliance requirements, including those related to safety, reliability and load growth, gas system planning, and transportation electrification, which generally assume that California will continue to pursue consistent environmental and climate-related policies. If the federal government withdraws its support for grid and infrastructure modernization or prohibits California from pursuing its environmental and climate-related policies, or if California changes its policies, SDG&E, SoCalGas and Sempra may be unable to meet their respective aims.

The occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We are subject to complex tax and accounting requirements that expose us to risks.

We are subject to complex tax and accounting requirements. These requirements may undergo changes at the federal, state, local and foreign levels, including in response to economic or political conditions. Compliance with these requirements, including changes to them or how they are implemented, interpreted or enforced, could increase our operating costs and materially adversely affect how we conduct our business. New tax legislation, regulations or interpretations or changes in tax policies in the U.S., Mexico or other countries in which we operate or do business could negatively affect our tax expense and/or tax balances and our businesses generally. Any failure to comply with these requirements could subject us to fines and penalties, including criminal penalties in some cases. The occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We may be negatively impacted by the outcome of litigation or other proceedings in which we are involved.

Our businesses are involved in a number of lawsuits, appeals, binding arbitrations, regulatory investigations and other proceedings. We discuss material pending proceedings in Note 15 of the Notes to Consolidated Financial Statements. Our businesses also may become involved in new proceedings that we do not consider material, such as the approximately 28,000 proofs of claim that have been filed on behalf of persons who assert the right to file lawsuits in the future based on alleged exposure to asbestos in power plants designed and/or built by certain predecessor entities we acquired in connection with our acquisition of our majority interest in Oncor. We have spent, and continue to spend, substantial money, time and employee and management focus on lawsuits and other proceedings. The uncertainties inherent in lawsuits and other proceedings make it difficult to estimate with any degree of certainty the timing, costs and ranges of costs or outcome of these matters, and changes or disruptions to the judicial system, such as the nationwide strike by the Mexican judiciary in 2024 in response to recent Mexican Constitutional reforms that require all judges to be elected rather than appointed, could result in delays, increased costs, or unfavorable outcomes. In addition, juries have demonstrated a willingness to grant large awards, including punitive damages, in response to personal injury, product liability, property damage, nuisance, and other claims. Accordingly, actual costs incurred have and may continue to differ materially from insured or reserved amounts and may not be recoverable, in whole or in part, from insurance or in customer rates. Any of the foregoing could cause reputational damage and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

RISKS RELATED TO SEMPRA CALIFORNIA

Operational Risks

Wildfires in California pose risks to Sempra, SDG&E and SoCalGas.

More and Increasingly Severe Wildfires

In recent years, California has experienced some of the largest wildfires (measured by acres burned and/or structures destroyed) in its history. Frequent and severe drought conditions, inconsistent and extreme swings in precipitation, changes in vegetation, unseasonably warm temperatures, low humidity, strong winds and other factors have increased the duration of the wildfire season and the intensity, prevalence and difficulty of prevention and containment of wildfires in California, including in SDG&E’s and SoCalGas’ service territories. Changing weather patterns, including as a result of climate change, could exacerbate these conditions. Certain of California’s local land use policies and forestry management practices have allowed for the construction and development of residential and commercial projects in high-risk fire areas, which could lead to increased third-party claims and greater losses related to fires for which SDG&E or SoCalGas may be liable. The LA Fires damaged some of SoCalGas’ natural gas infrastructure and significant third-party property and resulted in service disruptions in some of its service territory.

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Future wildfires in SDG&E’s or SoCalGas’ service territories could compromise SDG&E’s and SoCalGas’ electric and natural gas infrastructure and result in further service disruptions. Any such wildfires in SDG&E’s and SoCalGas’ territories (or outside of SDG&E’s territory in the event the Wildfire Fund is materially diminished) could materially adversely affect SDG&E’s, SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects, which we discuss further in this risk factor below and above under “Risks Related to All Sempra Businesses – Operational Risks.”

The Wildfire Legislation

In July 2019, the Wildfire Legislation was signed into law, which we discuss in Note 1 of the Notes to Consolidated Financial Statements. The Wildfire Legislation’s legal standard for the recovery of wildfire costs may not be implemented effectively or applied consistently, we may not be eligible for the Wildfire Legislation’s cap on wildfire-related liability if SDG&E fails to maintain a valid annual safety certification from the OEIS or meet other requirements, and/or the Wildfire Fund could be exhausted due to claims against the fund by SDG&E or other participating IOUs as a result of fires in their respective service territories, any of which could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects. PG&E is seeking reimbursement from the Wildfire Fund for losses associated with the Dixie Fire, which burned from July 2021 through October 2021. In addition, fires of the size and scope of the recent LA Fires, if found to have been caused by a participating IOU, could have a material adverse effect on the Wildfire Fund. In the case of the LA fires, the causes of these fires have not been determined and therefore these fires may not impact the Wildfire Fund.

In addition, the Wildfire Legislation did not change the doctrine of inverse condemnation, which imposes strict liability (meaning that liability is imposed regardless of fault) on a utility whose equipment is determined to be a cause of a fire. In such an event, the utility would be responsible for the costs of damages, including business interruption losses, interest and attorneys’ fees, even if the utility is not found negligent. In the past, the CPUC has denied recovery of incurred costs associated with wildfire claims despite the doctrine of inverse condemnation, which was historically based on the ability of a utility to pass such costs through to rate payers. The doctrine of inverse condemnation also is not exclusive of other theories of liability, such as negligence, under which additional liabilities, such as fire suppression, clean-up and evacuation costs, medical expenses, and personal injury, punitive and other damages, could be imposed. We are unable to predict the impact of the Wildfire Legislation on SDG&E’s ability to recover costs and expenses if SDG&E’s equipment is determined to be a cause of a fire, and specifically in the context of the application of inverse condemnation.

Cost Recovery Through Insurance or Rates

As a result of California’s doctrine of inverse condemnation, substantial losses recorded by insurance companies, and increased wildfire risk, obtaining insurance coverage for wildfires potentially associated with SDG&E’s equipment (or, to a lesser extent, SoCalGas) has become increasingly difficult and costly. If these conditions continue or worsen, including as a result of the LA Fires, insurance for wildfire liabilities may become unavailable or may become prohibitively expensive and we may be denied recovery of insurance cost increases through the regulatory process. In addition, insurance for wildfire liabilities may not be sufficient to cover all losses we may incur, or it may not be available to meet the $1.0 billion of primary insurance required by the Wildfire Legislation. Wildfire insurance may also become prohibitively expensive or unavailable for homeowners and businesses in SDG&E’s service territory, potentially increasing SDG&E’s financial exposure if a wildfire is found to be caused by SDG&E’s equipment. We are unable to predict whether we would be able to recover in rates or from the Wildfire Fund the amount of any uninsured losses. A loss that is not fully insured, is not sufficiently covered by the Wildfire Fund and/or cannot be recovered in customer rates could materially adversely affect Sempra’s and one or both of SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.

Wildfire Mitigation Efforts

Although we expend significant resources on measures designed to mitigate wildfire risks, these measures may not be effective in preventing wildfires or reducing our wildfire-related losses, and their costs may not be fully recoverable in rates. SDG&E is required by California law to submit wildfire mitigation plans for approval by the OEIS and could be subject to increased risks if these plans are not approved in a timely manner or SDG&E is determined to not have substantially complied with its approved plans, including the risk of fines or penalties for noncompliance. One of our wildfire mitigation strategies is to de-energize certain circuits for safety when there is elevated weather-related wildfire ignition risk. These “public safety power shutoffs” have been subject to scrutiny by various stakeholders, including customers, regulators and lawmakers, which could increase the risk of liability for damages associated with these events if SDG&E is found not to have acted within applicable guidelines and regulations. Such costs may not be recoverable in rates. Unrecoverable costs, adverse legislation or rulemaking, stakeholder scrutiny, ineffective wildfire mitigation measures or other negative effects associated with these efforts could materially adversely affect SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.

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The electricity industry is undergoing significant change, including increased deployment of renewable energy sources and energy storage, technological advancements, evolving procurement service standards, and political and regulatory developments.

Electric utilities in California are experiencing increasing deployment of solar and wind generation, including DER, energy storage and energy efficiency and demand management technologies, and California’s environmental policy objectives are accelerating the pace and scope of these changes. This growth will require further modernization of the electric grid to, among other things, accommodate increasing two-way flows of electricity and increase the grid’s capacity to interconnect these resources. In addition, attaining California’s clean energy goals will require sustained investments in transmission and distribution grid modernization, renewable energy integration projects, energy efficiency programs, operational and data management systems, and electric vehicle and energy storage infrastructure, which may increase exposure to overall grid instability and technology obsolescence. The growth of third-party energy storage alternatives and other technologies also may increasingly compete with SDG&E’s traditional transmission and distribution infrastructure in delivering electricity to consumers. Certain FERC transmission development projects are open to competition, allowing independent developers to compete with incumbent utilities for the construction and operation of transmission facilities. The CPUC is conducting various proceedings regarding DER, including the evaluation of special programs and pilot projects; changes to the planning and operation of the electric grid to prepare for higher penetration of DER; future grid modernization investments; the deferral of traditional grid investments by DER; and the role of the electric grid operator. These proceedings and the broader changes in California’s electricity industry could result in new regulations, policies and/or operational changes that could materially adversely affect SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Most of SDG&E’s customers receive electric procurement service from a load-serving entity other than SDG&E through programs such as CCA and DA. CCA is only available if a customer’s local jurisdiction (city or county) offers such a program, as is the case with the City of San Diego and certain other jurisdictions in SDG&E’s service territory, and DA is currently limited by a cap based on gigawatt hours. As a result of customers electing CCA and DA services, SDG&E’s historical energy procurement commitments for future deliveries exceed the needs of its remaining bundled customers. To help achieve the goal of ratepayer indifference (as to whether customers’ energy is procured by SDG&E or by CCA or DA), the CPUC revised the Power Charge Indifference Adjustment framework. The framework is intended to more equitably allocate SDG&E’s procurement cost obligations among customers served by SDG&E and customers now served by CCA and DA. If the framework or other mechanisms designed to achieve ratepayer indifference do not perform as intended, if the law changes, or if the law is not interpreted or enforced as expected, SDG&E’s remaining bundled customers could experience large increases in rates for commodity costs under commitments made on behalf of CCA and DA customers prior to their departure or, if all such costs are not recoverable in rates, SDG&E could experience material increases in its unrecoverable commodity costs. Any of these outcomes could have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Natural gas continues to be the subject of political and public debate, including a desire by some to reduce or eliminate reliance on natural gas as an energy source.

Certain California legislators, regulators and other stakeholders have expressed a desire to limit or eliminate reliance on natural gas as an energy source through increased use of renewable electricity and electrification. Reducing methane emissions also has become a major focus of certain local, state and federal agencies, resulting in passed or proposed legislation, regulation, policies and ordinances to prohibit or restrict the use of natural gas in new buildings, appliances and other applications. These actions could have the effect of reducing natural gas use over time, and the combination of reduced load and increasing costs to maintain the gas system could negatively impact affordability for remaining natural gas customers.

In February 2017, the CPUC opened proceeding SB 380 OII relating to SoCalGas to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility while still maintaining energy and electric reliability for the region, including analyzing alternative means for meeting or avoiding the demand for the facility’s services if it were eliminated. In December 2024, the CPUC approved an FD in the SB 380 OII finding that the Aliso Canyon natural gas storage facility is currently necessary for natural gas and electric reliability and affordable rates and closed the OII. Among other things, and subject to future CPUC biennial reviews and potential additional proceedings, the FD authorizes the Aliso Canyon natural gas storage facility to continue operating and sets the maximum working natural gas storage level at 68.6 bcf. If the Aliso Canyon natural gas storage facility were to be permanently closed or if future cash flows from its operation were otherwise insufficient to recover its carrying value, we would record an impairment of the facility, which could be material, we could incur materially higher than expected operating costs and/or be required to make material additional capital expenditures (any or all of which may not be recoverable in rates), and natural gas reliability and electric generation could be jeopardized. Any such outcome could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects. We discuss proceeding SB 380 OII in Note 15 of the Notes to Consolidated Financial Statements.

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CARB, California’s primary regulator for GHG emissions reduction programs, is evaluating various options for reducing natural gas demand through building decarbonization measures and is considering a proposed statewide zero-emissions standard for space and water heaters. Additionally, the CEC adopted changes to the Title 24 California Building Standards Code that require newly constructed residential and commercial buildings to include heat pump technologies for space and water heating beginning in 2026.

The CPUC has an open proceeding to establish policies, processes, and rules governing safe and reliable gas system operation and long-term gas system infrastructure planning for natural gas utilities in alignment with California’s decarbonization goals. Potential outcomes include reductions in natural gas demand over time in favor of electrification, renewable energy alternatives, and/or cleaner fuels and changes to rate and cost recovery policies.

A substantial reduction in or the elimination of natural gas use in California without adequate recovery of investments could result in impairment of some or all of SoCalGas’ and SDG&E’s natural gas infrastructure assets if they were not permitted to be repurposed for alternative fuels, were required to be depreciated on an accelerated basis or were to become stranded, which could have a material adverse effect on SoCalGas’, SDG&E’s and Sempra’s results of operations, financial conditions, cash flows and/or prospects.

SDG&E may incur significant costs and liabilities from its partial ownership of a nuclear facility being decommissioned.

SDG&E has a 20% ownership interest in SONGS, which we discuss in Note 14 of the Notes to Consolidated Financial Statements. SDG&E and each of the other owners of SONGS is responsible for financing its share of the facility’s expenses and capital expenditures, including those related to decommissioning activities. Although the facility is being decommissioned, SDG&E’s ownership interest in SONGS continues to subject it to risks, including:

▪the potential release of radioactive material

▪the potential harmful effects from the former operation of the facility

▪limitations on the insurance commercially available to cover losses associated with operating and decommissioning the facility

▪uncertainties with respect to the technological, financial, and political aspects of decommissioning the facility and the long-term storage of radioactive materials

SDG&E maintains the SONGS NDT to provide funds for nuclear decommissioning. Trust assets generally have been invested in equity and debt securities, which are subject to market fluctuations. A decline in the market value of trust assets, an adverse change in the law regarding funding requirements for decommissioning trusts, or changes in assumptions or forecasts related to decommissioning dates, technology and the cost of labor, materials and equipment due to inflationary pressures or otherwise could increase the funding requirements for these trusts, which costs may not be fully recoverable in rates. In addition, CPUC approval is required to make withdrawals from the NDT, and CPUC approval for certain expenditures may be denied if the CPUC determines the expenditures are unreasonable. In addition, decommissioning may be materially more expensive than we currently anticipate and therefore decommissioning costs may exceed the amounts in the NDT. Rate recovery for overruns would require CPUC approval, which may not occur.

The occurrence of any of these events could result in a reduction in our expected recovery and have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Legal and Regulatory Risks

SDG&E and SoCalGas are subject to extensive regulation.

Rates and Other Financial Matters

The CPUC regulates SDG&E’s and SoCalGas’ customer rates, except for SDG&E’s electric transmission rates that are regulated by the FERC, and conditions of service. The CPUC also regulates SDG&E’s and SoCalGas’ sales of securities, rates of return, capital structure, rates of depreciation, long-term resource procurement and other financial matters in various ratemaking proceedings. The CPUC periodically approves SDG&E’s and SoCalGas’ customer rates based on authorized capital expenditures, operating costs, including income taxes, and an authorized rate of return on investments while incorporating a risk-based decision-making framework, as well as certain settlements with third parties and mandatory social programs. The timing and outcome of ratemaking proceedings can be affected by various factors, many of which are not in our control, including the level of opposition by intervening parties; any rejection by the CPUC of settlements with third parties; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of regulators, customers and other stakeholders.

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These ratemaking proceedings include decisions about major programs in which SDG&E and SoCalGas make investments under an approved CPUC framework, such as wildfire mitigation and pipeline and storage integrity and safety enhancement programs, but which investments may remain subject to a CPUC filing or reasonableness review that may result in the disallowance of incurred costs. SDG&E and SoCalGas also may be required to make investments and incur other costs to comply with proposed legislative and regulatory requirements and initiatives, including those related to California’s climate goals and policies, and the ability to recover these costs and investments may depend on the final form of the legislative or regulatory requirements and the corresponding ratemaking mechanisms. Recovery may be delayed and/or insufficient if the applicable ratemaking mechanism involves a significant time lag between when costs are incurred and when those costs are recovered in rates or if there are material differences between the authorized costs embedded in rates (which are set on a prospective basis) and the actual costs incurred. Delays may also result from the administrative process, or the CPUC may deny recovery altogether on the basis that costs were not reasonably or prudently incurred or for other reasons, such as customer affordability. Even if recoverable, simultaneously investing in support of necessary safety and reliability and the regulatory requirements and demand for reliable lower-carbon energy may negatively impact the affordability of SDG&E’s and SoCalGas’ customer rates and their and Sempra’s results of operations, financial condition, cash flows and/or prospects.

A CPUC cost of capital proceeding every three years determines a utility’s authorized capital structure and authorized return on rate base. The CCM applies in the interim years and considers changes in the cost of capital based on changes in interest rates based on the applicable utility bond index published by Moody’s (CCM benchmark rate) for each 12-month period ending September 30 (the measurement period). Alternatively, each of SDG&E and SoCalGas is permitted to file a cost of capital application to have its cost of capital determined in lieu of the CCM in an interim year in which an extraordinary or catastrophic event materially impacts its cost of capital and affects utilities differently than the market as a whole. In October 2024, the CPUC issued an FD to modify the CCM. The FD updates the upward or downward adjustment to authorized ROE, if the CCM is triggered, from 50% to 20% of the change in the benchmark rate during the measurement period. Any further rate changes due to a downward trigger of the CCM or the denial by the CPUC of an automatic upward trigger of the CCM could have a material adverse effect on Sempra’s and the applicable utility’s results of operations, financial condition, cash flows and/or prospects. We discuss the CCM in “Part I – Item 1. Business - Ratemaking Mechanisms – Sempra California – Cost of Capital Proceedings,” and in Note 4 of the Notes to Consolidated Financial Statements.

The FERC regulates electric transmission rates, the transmission and wholesale sales of electricity in interstate commerce, transmission access, the rates of return on investments in electric transmission assets, and other similar matters involving SDG&E. These ratemaking mechanisms are subject to many risks similar to those described above regarding the CPUC ratemaking proceedings. In particular, SDG&E’s authorized TO5 settlement provided for an ROE of 10.60%, consisting of a base ROE of 10.10% plus the California ISO adder. In December 2024, the FERC issued an order, which SDG&E has appealed, finding that SDG&E is not eligible for the California ISO adder and that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019. In October 2024, SDG&E submitted its TO6 filing to the FERC, requested to be effective January 1, 2025, and subject to refund. SDG&E’s TO6 filing proposes, among other items, an increase to SDG&E’s currently authorized base ROE from 10.10% to 11.75% plus the California ISO adder, for a total ROE of 12.25%. In December 2024, the FERC accepted SDG&E’s TO6 filing but suspended the effective date to June 1, 2025 and disallowed the inclusion of the California ISO adder, which SDG&E has appealed. Any unfavorable outcome in these proceedings, such as the discontinuation of the California ISO adder or not being successful in our appeal of the FERC decision finding that the TO5 adder refund provision was triggered, could have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.

CPUC Authority Over Operational Matters

Our operations are subject to CPUC rules (and similar FERC rules), commonly referred to as “affiliate rules,” relating to transactions among SDG&E, SoCalGas and other Sempra businesses. These rules primarily impact market transactions and marketing activities involving transmission supply and capacity, including sales or other trades of natural gas or electricity within or among SDG&E and SoCalGas and Sempra and its covered affiliates. Noncompliance with these rules, as well as any changes to these rules or their interpretations or additional more restrictive CPUC or FERC rules related to transactions with affiliates, could materially adversely affect our operations and, in turn, our results of operations, financial condition, cash flows and/or prospects.

Additionally, the CPUC has regulatory authority related to safety standards and practices, reliability and planning, competitive conditions and a wide range of other operational matters, including citation and enforcement programs concerning matters such as safety activity, disconnection and billing practices, resource adequacy and environmental compliance. Many of these standards and citation and enforcement programs are becoming more stringent and could subject a utility to significant penalties and fines, as well as higher operating costs. The CPUC conducts reviews and audits of the matters under its authority and may launch

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investigations or open proceedings at its discretion, the results of which could include citations, disallowances, fines and penalties, as well as corrective or mitigation actions to address any noncompliance, any of which may not be sufficiently funded by customer rates or at all. Any such occurrence could result in other regulatory exposure, significant litigation, and reputational harm and could have a material adverse effect on SDG&E’s, SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.

We discuss various CPUC proceedings relating to SDG&E and SoCalGas in Notes 4 and 15 of the Notes to Consolidated Financial Statements.

Regulatory Changes and Influence of Other Organizations

SDG&E and SoCalGas incur significant capital, operating, and other costs associated with regulatory compliance. SDG&E, SoCalGas and Sempra may be materially adversely affected by revisions or reinterpretations of existing or new legislation, regulations, decisions, orders or interpretations of the CPUC, the FERC or other regulatory bodies, any of which could change how SDG&E and SoCalGas operate, affect their ability to recover various costs through rates or adjustment mechanisms, require them to incur additional expenses and compliance costs or otherwise materially adversely affect their and Sempra’s results of operations, financial condition, cash flows and/or prospects.

SDG&E and SoCalGas are also affected by numerous advocacy groups, including California Public Advocates Office, The Utility Reform Network, Utility Consumers’ Action Network and the Sierra Club. Success by any of these groups in directly or indirectly influencing legislators and regulators could have a material adverse effect on SDG&E’s, SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.

SoCalGas has incurred and may continue to incur significant costs, expenses and other liabilities related to the Leak.

From October 23, 2015 through February 11, 2016, SoCalGas experienced the Leak, which we describe in Note 15 of the Notes to Consolidated Financial Statements.

In September 2021, SoCalGas and Sempra entered into an agreement with counsel to resolve approximately 390 lawsuits including approximately 36,000 plaintiffs (the Individual Plaintiffs) then pending against SoCalGas and Sempra related to the Leak for a payment of up to $1.8 billion. Over 99% of the Individual Plaintiffs participated and submitted valid releases, and SoCalGas paid $1.79 billion in 2022 under the agreement. The Individual Plaintiffs who did not participate in the settlement (the Non-Settling Individual Plaintiffs) are able to continue to pursue their claims. As of February 19, 2025, there are approximately 520 plaintiffs who are either new plaintiffs that have filed new lawsuits related to the Leak or Non-Settling Individual Plaintiffs. This litigation seeks compensatory and punitive damages, property damage and diminution in property value, injunctive relief and civil penalties. Additional litigation may be filed against us related to the Leak or our responses to it. The costs of defending against, settling or otherwise resolving the pending lawsuits or any new litigation could materially adversely affect SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects. We discuss the risks associated with litigation above under “Risks Related to All Sempra Businesses – Legal and Regulatory Risks.”

SoCalGas’ loss contingency accruals do not include any amounts in excess of what has been reasonably estimated to resolve these matters, nor any amounts that may be necessary to resolve threatened litigation, other potential litigation or other costs. We are not able to reasonably estimate the possible loss or a range of possible losses in excess of the amounts accrued, which could be significant and could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Failure by the CPUC to adequately reform SDG&E’s electric rate structure could negatively impact SDG&E and Sempra.

The NEM program is an electric billing tariff mechanism designed to promote the installation of on-site renewable energy generation (primarily solar installations) for residential and business customers. Depending on when the on-site generation is installed, NEM customers receive a full retail rate or a reduced retail rate for energy they generate but do not use that is fed to the utility’s power grid, which results in these customers not paying their proportionate share of the cost of maintaining and operating the electric transmission and distribution system, subject to certain exceptions, but still receiving electricity from the system when their self-generation is inadequate to meet their electricity needs. As more and higher electric-use customers switch to NEM and self-generate energy, the burden on remaining non-NEM customers, who effectively subsidize the unpaid NEM costs, increases, which in turn encourages more self-generation and further increases rate pressure on remaining non-NEM customers.

The current electric residential rate structure in California is primarily based on consumption volume, which places a higher rate burden on customers with higher electric use while subsidizing lower-use customers. In December 2023, a new Net Billing Tariff

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was implemented for customers who interconnect their qualifying on-site renewable energy generation after April 2023. The new Net Billing Tariff revised the NEM structure for new customers with a retail export compensation rate that is better aligned with the value provided to the grid by behind-the-meter energy generation systems and retail import rates that encourage electrification and adoption of solar systems paired with storage. The new Net Billing Tariff is designed to compensate customers for the value of their exports to the grid based on avoided cost. Additionally, in response to California legislation adopted in 2022, the CPUC initiated a rulemaking to broadly restructure the way fixed costs are collected, moving away from volumetric only charges and incorporating an income-graduated fixed charge for default residential rates. The intent of such a fixed charge is to establish a rate structure that allows the utility to collect a greater portion of its fixed costs on a non-volumetric basis, advance the state’s climate goals through end-use electrification and provide a more affordable rate design on average for lower-income customers. In May 2024, the CPUC adopted a residential fixed charge with implementation expected to begin in the fourth quarter of 2025. Depending on the effectiveness of the new Net Billing Tariff and fixed charge, which are uncertain, the risks associated with the existing NEM tariff and rate design, including adverse impacts on electricity rates and the reliability of the transmission and distribution system and the potential for increased customer dissatisfaction, increased likelihood of noncompliance with CPUC or other safety or operational standards, and increased power procurement, operating, capital and other costs that may not be recoverable, could continue or increase, any of which could have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.

RISKS RELATED TO SEMPRA TEXAS UTILITIES

Operational and Structural Risks

Certain ring-fencing measures, governance mechanisms and commitments limit our ability to influence the management, operations and policies of Oncor.

Various “ring-fencing” measures, governance mechanisms and commitments are in place that create legal and financial separation between Oncor Holdings, Oncor and their subsidiaries, on the one hand, and Sempra and its affiliates and subsidiaries, on the other hand. These measures are designed to enhance Oncor’s separateness from its owners and mitigate the risk that Oncor would be negatively impacted by a bankruptcy or other adverse financial development affecting its owners. These measures subject us and Oncor to various restrictions, including:

▪seven members of Oncor’s 13-person board of directors must be independent directors in all material respects under the rules of the NYSE in relation to Sempra and its affiliates and any other owners of Oncor, and also must have no material relationship with Sempra or its affiliates or any other owners of Oncor currently or within the previous 10 years; of the six remaining directors, two must be designated by Sempra, two must be designated by Oncor’s minority owner, TTI, and two must be current or former Oncor officers

▪Oncor will not pay dividends or other distributions (except for contractual tax payments) if (i) a majority of Oncor’s independent directors or any of the directors appointed by TTI determines that it is in the best interest of Oncor to retain such amounts to meet expected future requirements, (ii) the payment would cause Oncor’s debt-to-equity ratio to exceed the debt-to-equity ratio approved by the PUCT, or (iii) unless otherwise allowed by the PUCT, Oncor’s senior secured debt credit rating by any of the Rating Agencies falls below BBB (or Baa2 for Moody’s)

▪there must be certain “separateness measures” maintained to reinforce the legal and financial separation of Oncor from Sempra, including a requirement that dealings between Oncor and Sempra or Sempra’s affiliates (other than Oncor Holdings and its subsidiaries) must be on an arm’s-length basis, limitations on affiliate transactions and a prohibition on pledging Oncor assets or membership interests for any entity other than Oncor

▪a majority of Oncor’s independent directors and the directors designated by TTI that are present and voting (with at least one required to be present and voting) must approve any annual or multi-year budget if the aggregate amount of capital expenditures or O&M in the budget differs by more than 10% from the corresponding amounts in the budget for the preceding fiscal year or multi-year period, as applicable

As a result of these measures, we do not control Oncor Holdings or Oncor, and we have limited ability to direct the management, operations and policies of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends or other distributions, strategic planning and other important matters. Moreover, all directors of Oncor, including the directors we have appointed, have considerable autonomy and have a duty to act in the best interest of Oncor consistent with the approved ring-fence and Delaware law, which may in some cases be contrary to our interests. To the extent the directors approve or Oncor otherwise pursues actions that are not in our interest, our results of operations, financial condition, cash flows and/or prospects may be materially adversely affected.

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Industry-Related Risks

Changes in the regulation of Oncor or the regulation or operation of the electric utility industry and/or the ERCOT market could negatively affect Oncor.

Oncor operates in the electric utility industry and is subject to many of the same or similar risks as SDG&E and SoCalGas as we describe above under “Risks Related to All Sempra Businesses” and “Risks Related to Sempra California,” particularly with respect to our operational risks, financial risks and specifically regulation by federal, state, and local legislative and regulatory authorities regarding rates and other financial and operational matters. Oncor operates in the ERCOT market. In ERCOT, rates are set by the PUCT based on a historical test year, and as a result, the rates Oncor is allowed to charge generally will not exactly match its costs at any given point in time and there is no assurance that it will be able to timely or fully recover its actual costs and/or earn its full return on invested capital, particularly during periods of increased capital spending by Oncor, high inflation, or increases in general interest rates relative to Oncor’s most recent base rate review. Further, the approved levels of recovery could be significantly less than requested levels, and the approved timing for recovery could differ from proposed timelines. In addition to requests to recover its costs, Oncor’s rate proceedings may contain other requests. Failure to receive approval of its requests in any rate proceeding could adversely impact Oncor, which could adversely impact us, and those impacts could be material.

The costs and burdens associated with complying with the various legislative and regulatory requirements to which Oncor is subject at the federal, state, and local levels and adjusting Oncor’s business and operations in response to legislative and regulatory developments, including changes in ERCOT, and any fines or penalties that could result from any noncompliance, may have a material adverse effect on Oncor. In addition, insufficient electric capacity within ERCOT or significant changes within ERCOT or to the ERCOT market structure that impact transmission and distribution utilities, including adverse publicity or public perception, additional regulatory requirements or oversight, could materially adversely affect Oncor. Moreover, legislative, regulatory, market or industry activities could adversely impact Oncor’s collections and cash flows and jeopardize the predictability of utility earnings. For instance, the PUCT has instituted various projects reviewing the regulatory framework regarding DER and other non-traditional technologies. As DER usage continues to grow, related regulatory decisions, including with respect to ERCOT market rules and transmission and distribution utilities’ ability to invest in non-traditional electricity delivery solutions, could adversely impact Oncor’s revenues and operations. Additionally, projected load growth across the ERCOT system could, if not sufficiently addressed through system design and reliability measures, negatively impact electric infrastructure reliability and potentially cause system-wide stresses. If Oncor does not successfully respond to applicable legislative, regulatory, market or industry developments, Oncor could suffer a deterioration in its results of operations, financial condition, cash flows and/or prospects, which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

Financial Risks

Oncor could have liquidity needs that necessitate additional investments.

Oncor’s business is capital-intensive, with significant and increasing capital spending expected in future periods, and it relies on external financing as a significant source of liquidity for its capital requirements. In the past, Oncor has financed much of its cash needs from operations and with proceeds from indebtedness, but these sources of capital may not be adequate or available at reasonable prices or on other reasonable terms in the future, or at all. Because our commitments to the PUCT prohibit us from making loans to Oncor, we may elect to make capital contributions to Oncor if it fails to meet its capital requirements or is unable to access sufficient capital from other sources to finance its ongoing needs. Any such investments could be substantial, would reduce the cash available to us for other purposes, may not be recovered, and could increase our indebtedness, any of which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

Sempra could incur substantial tax liabilities if EFH’s 2016 spin-off of Vistra is deemed to be taxable.

As part of its bankruptcy proceedings, in 2016, EFH distributed all the outstanding shares of common stock of its subsidiary Vistra Corp. (formerly Vistra Energy Corp. and referred to herein as Vistra) to certain creditors of TCEH LLC (the spin-off), and Vistra became an independent, publicly traded company. Vistra’s spin-off from EFH was intended to qualify for partially tax-free treatment to EFH and its shareholders under Sections 368(a)(1)(G), 355 and 356 of the U.S. Internal Revenue Code of 1986 (as amended) (collectively referred to as the Intended Tax Treatment). In connection with and as a condition to the spin-off, EFH received a private letter ruling from the IRS regarding certain issues relating to the Intended Tax Treatment, as well as tax opinions from counsel to EFH and Vistra regarding certain aspects of the spin-off not covered by the private letter ruling.

In connection with the merger of EFH with a subsidiary of Sempra (the Merger), EFH received a supplemental private letter ruling from the IRS and Sempra and EFH received tax opinions from their respective counsels that generally provide that the

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Merger will not affect the conclusions reached in, respectively, the IRS private letter ruling and tax opinions issued with respect to the spin-off described above. Similar to the IRS private letter ruling and opinions issued with respect to the spin-off, the supplemental private letter ruling is generally binding on the IRS and any opinions issued with respect to the Merger are based on factual representations and assumptions, as well as certain undertakings, made by Sempra and EFH. If such representations and assumptions are untrue or incomplete, any such undertakings are not complied with, or the facts upon which the IRS supplemental private letter ruling or tax opinions (which will not impact the IRS position on the transactions) are based are different from the actual facts relating to the Merger, the tax opinions and/or supplemental private letter ruling may not be valid and could be challenged by the IRS. Even though Sempra Texas Holdings Corp. would have administrative appeal rights if the IRS were to invalidate its private letter ruling and/or supplemental private letter ruling, including the right to challenge any adverse IRS position in court, any such appeal would be subject to uncertainties and could fail. If it is ultimately determined that the Merger caused the spin-off not to qualify for the Intended Tax Treatment, Sempra, through its ownership of Sempra Texas Holdings Corp., could incur substantial tax liabilities, which would materially reduce the value associated with our investment in Oncor and could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

RISKS RELATED TO SEMPRA INFRASTRUCTURE

Operational Risks

Project development activities may not be successful, projects under construction may not be completed on schedule or within budget, and completed projects may not operate at expected levels or generate expected earnings or cash flows.

Energy Infrastructure Projects

We are involved in a number of energy infrastructure projects in various stages of development and construction, which subject us to numerous risks. Success in developing each project depends on, among other things:

▪our financial condition and cash flows and other factors that impact our ability to invest sufficient funds in the project, including for preliminary activities conducted before we determine whether the project is feasible or economically attractive

▪project assessment and design and our ability to foresee and incorporate new and developing trends and technologies in the energy industry, such as projects and design solutions to help enable our and our customers’ climate goals

▪our ability to reach a final investment decision or meet other milestones, which may be influenced by external factors outside our control, including the global economy and energy and financial markets, actions by regulators, achieving necessary internal and external approvals, and many of the other factors described in this risk factor

▪negotiation of satisfactory EPC agreements and renegotiation in the event of delays in final investment decisions or failures to meet other specified deadlines

▪identification of suitable partners, customers, contractors, suppliers and other necessary counterparties

▪progressing relationships from MOUs, HOAs or similar arrangements, which are non-binding, to execution of binding, definitive agreements and participation in the project

▪negotiation and maintenance of satisfactory equity, purchase, sale, supply, transportation and other appropriate commercial agreements, and satisfaction of any conditions to effectiveness of such agreements, including reaching a positive final investment decision within agreed timelines

▪timely receipt and maintenance of required governmental permits, licenses and other authorizations under terms we find reasonable

▪our project partners’, contractors’, equipment providers’ and other vendors’ and counterparties’ willingness and financial or other ability to make their required investments or fulfill their contractual commitments on a timely basis

▪timely, satisfactory and on-budget completion of construction, which could be negatively affected by engineering problems, work stoppages, unavailability or increased costs of materials, equipment, labor and commodities due to inflation or supply chain or other issues, and a variety of other factors, many of which we discuss above under “Risks Related to All Sempra Businesses – Operational Risks” and elsewhere in this risk factor

▪implementation of new or changes to existing laws or regulations that impact our infrastructure or the energy sector generally

▪obtaining satisfactory financing for the project, particularly when inflation and interest rates are volatile

▪the absence of hidden defects on or inherited environmental liabilities for the site of the project

▪timely and cost-effective resolution of any litigation or unsettled property rights affecting the project

▪geopolitical events and other uncertainties

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Any failures with respect to the above factors or other factors material to any particular project could involve additional costs, otherwise negatively affect our ability to successfully complete the project and force us to impair or write off amounts we have invested in the project. If we are unable to complete a development project, if we experience delays, or if construction, financing or other project costs exceed our estimated budgets and we are required to make additional capital contributions, we may not receive an adequate or any return on our investment and other resources expended on the project and our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.

The operation of existing facilities and any future projects we complete involves many risks, including the potential for unforeseen design flaws, engineering challenges, or the breakdown for other reasons of facilities, equipment or processes; labor disputes or shortages; fuel interruption; environmental contamination; increasing regulatory requirements, including from regulations aiming to reduce GHG emissions; and the other operational risks that we discuss above under “Risks Related to All Sempra Businesses – Operational Risks.” Any of these events could lead to our facilities being idle or operating below expected levels, which may result in lost revenues or increased expenses, including higher maintenance costs and penalties. Any such occurrence could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

LNG Projects

In addition to the risks described above that are applicable to all our energy infrastructure projects, our LNG projects, which we discuss in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure,” also face distinct disadvantages relative to some LNG projects being pursued by other project developers, including:

▪The proposed Cameron LNG Phase 2 project is subject to certain restrictions and conditions under the JV project financing agreements for the Cameron LNG Phase 1 facility and requires unanimous consent of all the members, including with respect to the equity investment obligation of each member. We may not be able to satisfy the conditions under the financing agreements, receive members’ consent, obtain satisfactory conclusion on the EPC process, or obtain the extension of our non-FTA approval, in which case our ability to develop the Cameron LNG Phase 2 project would be jeopardized.

▪The ECA LNG projects under construction and in development are subject to ongoing land and permit disputes and recent and proposed changes to the Mexican Constitution and certain laws in Mexico that could obstruct efforts to find or maintain suitable partners, customers and financing arrangements and hinder or halt construction and, if the projects are completed, operations. We discuss these risks under “Risks Related to Sempra Infrastructure – Legal and Regulatory Risks.” In addition, the Mexican regulatory process and overlay of U.S. regulation for natural gas exports to LNG facilities in Mexico are not well developed, which, among other factors, contributed to delays in obtaining a necessary permit from the Mexican government for the ECA LNG Phase 1 project and could cause similar delays or other hurdles in the future and lead to difficulties finding or maintaining suitable partners, customers and financing arrangements. Further, while we do not expect the construction or operation of the ECA LNG Phase 1 project to disrupt operations at the ECA Regas Facility, we expect construction of the proposed ECA LNG Phase 2 project would conflict with the current operations at the ECA Regas Facility, which currently has firm storage service agreements and nitrogen injection service agreements with Shell and SEFE that expire in May 2028 and December 2025, respectively. In addition, the Baja California region does not have extensive sources of natural gas, and at times, particularly during the summer, natural gas supply to the region is severely constrained and may impact our costs and our ability to source all feed gas required under our ECA LNG Phase 1 supply contracts.

▪The PA LNG Phase 1 project under construction is located at a greenfield site and is therefore subject to certain disadvantages relative to other projects being constructed or developed at brownfield sites, such as increased time and costs to develop and construct the project due to lack of existing infrastructure. The PA LNG Phase 2 project in development would be located at the site of the PA LNG Phase 1 project and would therefore be subject to certain advantages, as well as potential disadvantages, relative to projects being developed at greenfield sites. Advantages of brownfield development include the ability to leverage existing permits and infrastructure; disadvantages of brownfield development could include increased complexity of integrating new facilities with existing infrastructure. Additionally, in February 2020, Sempra Infrastructure filed an application with the DOE to permit LNG produced from the proposed PA LNG Phase 2 project to be exported to all current and future non-FTA countries, which we may not receive on a timely basis or at all.

Development and operation of these or any other LNG projects will depend on the expansion of our existing pipeline interconnections or the ability to permit and construct new pipeline facilities, each of which may require us to enter into additional pipeline interconnection agreements with third-party pipelines, which may not be possible on reasonable terms or at all.

The capital requirements for our LNG projects can be significant, even if we decide not to make a positive final investment decision. As has happened in the past, our proposed facilities may not be completed in accordance with estimated timelines or budgets or at all as a result of the above or other factors, and delays, cost overruns or our inability to complete one or more of these projects could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

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We face risks from increased competition.

The markets in which we operate are characterized by numerous capable competitors, many of which have extensive and diversified development and/or operating experience domestically and internationally and financial resources similar to or greater than ours. In particular, the natural gas pipeline, storage and LNG market segments recently have been characterized by strong and increasing competition for winning new development projects and acquiring existing assets. These competitive factors could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We are exposed to additional competitive risks in connection with our LNG projects. Our ability to reach a final investment decision for each development project and, if a positive decision is made and a project is completed, the overall success of the project depends in part on global energy markets, which can increase competition for global LNG demand in a number of ways. In general, depressed natural gas and LNG prices in the markets intended to be served by any of our projects, including as a result of global oil prices and their associated current and forward projections or other factors, could reduce the pricing and cost advantages of exporting natural gas and LNG produced in North America, which could lead to decreased demand from our projects. Although demand for natural gas is currently strong due to increased focus on energy security and climate aims, a reduction in natural gas demand could also occur from higher penetration of alternative fuels in new power generation, reduced economic activity in general, or as a result of calls by some to limit or eliminate global reliance on natural gas. Further, because LNG projects take a number of years to develop and construct, it is difficult to match current and expected demand with the projected supply from projects under development. Moreover, shifts in U.S. and foreign energy policy could impact supply, demand and other matters critical to LNG projects, such as permitting and other approval processes. Both the U.S. and Mexico held federal elections in 2024, and LNG exports may face increased costs under the new Administrations due to changing macroeconomic and geopolitical conditions. Also, the DOE has recently implemented changes to its approach to requests for extensions of time to commence LNG exports under existing non-FTA approvals. These changes and other market factors such as oil prices could delay or hamper the development of U.S. LNG export facilities and make LNG projects in other parts of the world more feasible and competitive with LNG projects in North America, thus increasing supply and competition for global LNG demand. Any of these occurrences could impact competition and prospects for developing LNG projects and negatively affect the performance and prospects of any of our projects that are or become operational, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We may not be able to secure, maintain, extend or replace long-term supply, sales or capacity agreements.

Sempra Infrastructure’s ability to secure new or maintain, extend or replace existing long-term sales or capacity agreements for its natural gas pipeline operations depends on, among other factors, demand for and supply of LNG and/or natural gas from its transportation customers, which may include our LNG facilities. A decrease in demand for or supply of LNG or natural gas from such customers or the occurrence of other events that hinder Sempra Infrastructure from maintaining such agreements or establishing new ones could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

The electric generation and wholesale power sales industries are highly competitive. As more plants are built, supplies of energy and related products may exceed demand, competitive pressures may increase and wholesale electricity prices may decline or become more volatile. Without long-term power sales agreements, our revenues may be subject to increased volatility, and we may be unable to sell the power that Sempra Infrastructure’s facilities can produce at favorable prices or at all, any of which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

We rely on transportation assets and services, much of which we do not own or control, to deliver natural gas and electricity.

We depend on electric transmission lines, natural gas pipelines and other transportation facilities and services owned and operated by third parties to, among other things:

▪deliver the natural gas, LNG, electricity and LPG we sell to customers or use for our LNG facilities

▪supply natural gas to our gas storage and electric generation facilities

▪provide retail energy services to customers

If transportation is disrupted, the construction of necessary interconnecting infrastructure is not completed on schedule or at all or capacity is inadequate, we may be delayed in completing projects under development and/or unable to meet our contractual obligations to customers of those projects or existing projects, in which case we may be responsible for damages they incur, such as the cost of acquiring alternative supplies at then-current spot market rates, and we could lose customers that may be difficult to replace. Any such occurrence could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

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Financial Risks

Sempra Infrastructure’s business is capital-intensive and relies on various types of financing arrangements, which may not be adequate or available in the future.

Sempra Infrastructure’s business is capital-intensive, with significant and increasing capital spending expected in future periods. It relies on various types of financing to meet its capital requirements, including capital contributions from Sempra and NCI owners, as well as external financing such as loans and other forms of project financing that could impose guarantees, indemnities or other obligations. These arrangements could expose us to risks, including exposure to losses upon the occurrence of certain events related to the development, construction, operation or financing of the applicable projects. In addition, external sources of capital may not be adequate or available on reasonable terms. Any of these outcomes could have a material adverse effect on our future results of operations, financial condition, cash flows and/or prospects.

Fixed-price long-term contracts for services or commodities expose our businesses to inflationary pressures.

Sempra Infrastructure seeks to secure long-term contracts for services and commodities in an effort to optimize the use of its facilities, reduce volatility in earnings and support the construction of new infrastructure. Certain of these contracts are at fixed prices, and their profitability may be negatively affected by inflationary pressures, including increased labor, materials, equipment, commodities and other operational costs, rising interest rates that affect financing costs and changes in applicable exchange rates. We aim to mitigate these risks by, among other things, using variable pricing tied to market indices, anticipating and providing for cost escalation when bidding on projects, contracting for direct pass-through of operating costs and/or entering into hedges. However, these measures may not fully or substantially offset any increases in operating expenses or financing costs caused by inflationary pressures and their use could introduce additional risks, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Our international businesses and operations expose us to foreign currency exchange rate and inflation risks.

Our operations in Mexico pose foreign currency exchange rate and inflation risks. Exchange and inflation rates with respect to Mexico and fluctuations in those rates may have an impact on the revenue, cash flows and costs from our international operations, which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects. We sometimes attempt to hedge cross-currency transactions and earnings exposure through various means, including financial instruments and short-term investments, but these hedges may not fully achieve our objectives of mitigating earnings volatility that would otherwise occur due to exchange rate fluctuations. Because we do not hedge our net investments in foreign countries, we are susceptible to volatility in OCI caused by exchange rate fluctuations for entities whose functional currencies are not the U.S. dollar. Moreover, Mexico has experienced periods of high inflation and exchange rate instability in the past, and severe devaluation of the Mexican peso could result in governmental intervention to institute restrictive exchange control policies, as has occurred before in Mexico and other Latin American countries. We discuss our foreign currency exposure at our Mexican subsidiaries in “Part II – Item 7. MD&A” and “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Our businesses are exposed to fluctuations in commodity prices.

We buy energy-related commodities from time to time for pipeline operations, LNG facilities or power plants to satisfy contractual obligations with customers. The regional and other markets in which we purchase these commodities are competitive and can be subject to significant pricing volatility as a result of many factors, including inflation, adverse weather conditions, supply and demand changes, availability of competitively priced alternative energy sources, political and geopolitical instability, commodity production levels and storage capacity, energy and environmental legislation and regulations, and economic and financial market conditions. Our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected if the prevailing market prices for natural gas, LNG, electricity or other commodities we buy change in a direction or manner not anticipated and for which we have not provided adequately through purchase or sale commitments or other hedging transactions.

Legal and Regulatory Risks

Our international businesses and operations expose us to increased legal, regulatory, tax, economic, geopolitical, credit and management oversight risks and challenges.

We own or have interests in a variety of energy infrastructure assets in Mexico, and we do business with companies based in foreign markets, including particularly our LNG export operations. Conducting these activities in foreign jurisdictions subjects us to complex management, security, political, legal, economic and financial risks that vary by country, many of which may differ from and potentially be greater than those associated with our wholly domestic businesses, and the occurrence of any of these

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risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. These risks include the following and the other risks discussed in this risk factor below:

▪compliance with tax, trade, environmental and other foreign laws and regulations, including legal limitations on ownership in some foreign countries and inadequate or inconsistent enforcement of regulations

▪actions by local regulatory bodies, such as the CRE, including setting rates and tariffs that may be earned by or charged to our businesses

▪the timing and outcome of ratemaking proceedings can be affected by various factors, many of which are not in our control and recovery may be delayed and/or insufficient to recover our costs

▪adverse changes in social, political, economic or market conditions or the stability of foreign governments or such foreign governments’ relations with the U.S. government

▪adverse rulings by or instability in foreign courts or tribunals

▪challenges obtaining, maintaining and complying with permits or approvals

▪difficulty enforcing contractual and property rights and differing legal standards

▪expropriation or theft of assets

▪demand for hydrocarbon fuels, such as natural gas imported from the U.S., may be impacted by geopolitical factors

▪with respect to our non-utility international business activities, changes in the priorities and budgets of international customers, which may be driven by many of the factors listed above, among others

Mexican Government Influence on Economic and Energy Matters

The Mexican government exercises significant and increasing influence over the Mexican energy sector and has adopted or proposed additional changes that, in each case, could impact private investment in this sector.

Mexican governmental actions in the past several years in the electricity market include resolutions, orders, decrees, regulations and proposed and adopted amendments to Mexican law that could, among other things, threaten the prospects for private-party renewable energy generation in the country, limit the ability to dispatch renewable energy and receive or maintain operational permits, increase costs of electricity for legacy renewable and cogeneration energy contract holders, and limit ownership of energy assets by private companies. We discuss some of these actions in Note 15 of the Notes to Consolidated Financial Statements. Moreover, the government of Mexico has implemented Mexican Constitutional energy reforms that will impact energy infrastructure and markets in Mexico. We await legislative action to determine the potential impact such reforms will have on the market generally and our business in particular.

With respect to midstream and downstream activities, Mexico’s Hydrocarbons Law gives SENER and the CRE significant powers to suspend permits when a danger to national security, energy security, or the national economy is foreseen and to revoke permits under certain other circumstances, including for a failure to comply with certain minimum storage and other requirements or for violations of certain provisions established by SENER or the Hydrocarbons Law, as applicable. Recent Mexican Constitutional reforms have proposed to transfer significant powers from CRE to SENER; implementing legislation on these reforms is expected to be forthcoming.

Subsequent to the federal elections in Mexico in 2024 and, as noted above, the Mexican government has begun to introduce significant changes to the Mexican Constitution, which will require changes in laws, policies, and regulations in order to be implemented. These changes have included Mexican Constitutional reforms affecting the judiciary and the for-profit status of certain state-owned enterprises. The changes to the judiciary include a requirement that all judges be elected rather than appointed. The energy reforms have the potential to increase government control and participation in the energy sector and to create novel challenges for infrastructure development and operations. Additionally, a set of six energy-related laws, including modifications to the Hydrocarbons Law and Electricity Industry Law, were submitted to Mexico’s Congress in January 2025. The legislative session runs from February 1 to April 30, and the government is targeting approval by the end of March 2025. These reforms and any further Mexican Constitutional, legal or regulatory changes could affect the Mexican economy, energy sector and our businesses, the extent of which we currently are unable to predict.

If future governmental actions are proposed and passed or otherwise become effective, if efforts to enjoin enforcement or suspend or overturn adopted governmental actions fail, or if other similar actions by the Mexican government are taken to curb private-party participation in the energy sector, including through further amendments to Mexican laws, rules or the Mexican Constitution or increased investigative and enforcement activities, it may impact our ability to operate our facilities at existing levels or at all, result in increased costs for Sempra Infrastructure and for its power consumers, adversely affect our ability to develop new projects, result in decreased revenues and cash flows, and negatively impact our ability to recover the carrying values of our investments in Mexico, any of which could have a material adverse effect on our business, results of operations, financial condition, cash flows and/or prospects.

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U.S. and Foreign Laws and International Relations

Our international business activities are subject to laws and regulations in the U.S. and Mexico and other countries where we do business related to foreign operations and doing business internationally, including the U.S. Foreign Corrupt Practices Act, the Mexican Federal Anticorruption Law in Public Contracting (Ley Federal Anticorrupción en Contrataciones Públicas) and similar laws, and are sensitive to foreign policy, trade policy and other geopolitical factors related to or applicable in each of these countries. The current and the last U.S. Administrations have taken different stances with respect to international trade agreements, tariffs, immigration policy and other matters of foreign policy that impact trade and foreign relations. The current U.S. Administration proposed imposing new tariffs on Mexico that are currently deferred, but may become effective in the near term, and other tariffs could potentially be imposed by the current U.S. Administration. The Mexican government has announced plans to implement retaliatory tariffs in response to the U.S. Administration’s proposed tariffs, if and when they are imposed, but the details of those tariffs have not yet been disclosed. In addition, the U.S. Administration has announced tariffs on imports of steel and aluminum beginning on March 12, 2025. These materials are integral to the construction of energy infrastructure and could have a significant impact on the costs associated with the construction of the same, whether directly or indirectly. Other shifts in foreign policy could create uncertainty and result in or increase adverse effects on our businesses. Violations or alleged violations of the laws referred to above, as well as foreign policy positions, sanctions or imposition of new or greater tariffs that adversely affect imports and exports between the U.S., Mexican and other foreign countries where we conduct business, could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

We face risks related to unsettled property rights and titles in Mexico.

We are engaged in disputes regarding our title to the property in Mexico where our ECA Regas Facility is situated and our ECA LNG projects are expected to be situated, which we discuss in Note 15 of the Notes to Consolidated Financial Statements. In addition, we have and may in the future seek to obtain long-term leases or rights-of-way from governmental agencies or other third parties to operate our energy infrastructure on land we do not own. In addition to the risks associated with such property ownership and use that we describe above under “Risks Related to All Sempra Businesses – Operational Risks,” disputes regarding ownership or rights to any of these properties could lead to difficulties finding or maintaining suitable partners, customers and project financing arrangements and could hinder or halt our ability to construct and, if completed, operate the affected facilities or proposed projects. Any of these outcomes could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Sempra Infrastructure’s energy infrastructure assets may be considered by the Mexican government to be a public service or essential for the provision of a public service, in which case these assets and the related businesses could be subject to expropriation or nationalization, loss of concessions, renegotiation or annulment of existing contracts, and other similar risks. Any such occurrence could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

CYBERSECURITY RISK MANAGEMENT

Sempra, SDG&E and SoCalGas have cybersecurity risk management processes in place that are intended to protect the confidentiality, integrity, and availability of our critical infrastructure, systems and information. These cybersecurity risk management processes include cybersecurity incident response plans that are integrated into each entity’s respective enterprise risk management and emergency management programs.

Our cybersecurity processes are largely designed and assessed based on the National Institute of Standards and Technology Cybersecurity Framework and the DOE’s Cybersecurity Capability Maturity Model standards. This does not imply that we meet any technical standards, specifications, or requirements, only that we use these standards as a guide to help us identify, assess, and manage cybersecurity risks relevant to our business.

Our cybersecurity risk management processes include:

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▪risk assessments performed by internal personnel and third-party advisors designed to help identify material cybersecurity risks to our critical systems, information, services, and our broader enterprise information technology environments

▪information security teams principally responsible for developing and implementing (1) cybersecurity risk assessment processes, (2) information security controls, and (3) response plans to cybersecurity incidents

▪the use of external service providers, where appropriate, to assess, test or otherwise assist with aspects of our information security controls

▪cybersecurity awareness training and policies designed to address social engineering attacks targeting employees and contractors

▪cybersecurity incident response plans that include procedures for responding to and reporting, if applicable, certain cybersecurity incidents

▪risk management processes for third-party service providers, suppliers, and vendors

We have not identified risks from known cybersecurity threats, including as a result of any prior cybersecurity incidents, that have materially affected or are reasonably likely to materially affect our results of operations, financial condition, cash flows and/or prospects.

CYBERSECURITY GOVERNANCE

Sempra’s, SDG&E’s and SoCalGas’ respective boards of directors consider cybersecurity risk as part of their risk oversight function. The Sempra board of directors has delegated to its SST Committee, which is entirely composed of independent directors under the independence standards established by the NYSE, oversight of cybersecurity and other information and operational technology risks. The SST Committee reports to the Sempra board of directors regarding the Committee’s activities, including those related to cybersecurity. The SST Committee receives briefings on cybersecurity topics from Sempra’s chief information security officer, internal information security staff or external experts in part for continuing education on topics that impact public companies. The SST Committee as well as the SDG&E and SoCalGas boards of directors oversee management’s implementation of our cybersecurity risk management processes and receive regular reports from management on our material cybersecurity risks. In addition, management updates the SST Committee and SDG&E and SoCalGas boards of directors about certain cybersecurity incidents. The SDG&E and SoCalGas boards of directors receive briefings from SDG&E’s and SoCalGas’ chief information officer and internal information security staff. SDG&E’s and SoCalGas’ boards of directors also have safety committees that, at times, may oversee the matters described above on behalf of those companies’ respective boards of directors.

We have formed cybersecurity councils to provide overall corporate oversight for managing material risks from cybersecurity threats. The cybersecurity councils meet regularly to receive updates on cybersecurity developments at Sempra and our consolidated entities from their cybersecurity management teams.

Our cybersecurity management teams supervise efforts designed to prevent, detect, mitigate, and remediate cybersecurity risks and incidents through various means, which may include briefings from internal information security personnel; threat intelligence and other information obtained from governmental, public or private sources, including external consultants engaged by us; and alerts and reports produced by information security tools deployed in the information technology environment. Cybersecurity management also supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Sempra’s director of cybersecurity governance & chief information security officer provides additional oversight and support for the operational cybersecurity activities at our consolidated entities.

Our cybersecurity materiality assessment teams, which include chief information security officers, chief information officers, chief risk officers, chief accounting officers or chief financial officers, and general counsels, help assess the materiality of certain cybersecurity incidents.

The cybersecurity councils, cybersecurity management teams and materiality assessment teams include members with decades of operational experience as cybersecurity professionals as well as management with decades of service in the areas of information and operational technology and legal, compliance, financial reporting and enterprise risk management. Some of these members hold relevant degrees and certifications that we believe enhance our ability to manage and respond to cybersecurity risks, including, among others, bachelor’s and/or master’s degrees in cybersecurity and computer science as well as certified information systems security professional, certified incident handler, and certified information security manager certifications.

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ITEM 2. PROPERTIES

We own or lease land, warehouses, offices, operating and maintenance centers, shops and service facilities necessary to conduct our businesses. Each of the Registrants currently has adequate space and, if we need more space, we believe it is readily available. We discuss properties related to our electric, natural gas and energy infrastructure operations in “Part I – Item 1. Business” and Note 1 of the Notes to Consolidated Financial Statements.

ITEM 3. LEGAL PROCEEDINGS

We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses), including environmental proceedings described in Item 103(c)(3) of SEC Regulation S-K, except for the matters described in Note 15 of the Notes to Consolidated Financial Statements or referred to in “Part I – Item 1A. Risk Factors” or “Part II – Item 7. MD&A.”

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II.

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

MARKET INFORMATION

Sempra Common Stock

Our common stock is traded on the NYSE under the trading symbol SRE. At February 19, 2025, there were approximately 19,241 record holders of our common stock. Information concerning dividend declarations for Sempra is included in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sources and Uses of Cash – Dividends.”

Market for Sempra’s Common Stock

Sempra’s common stock began trading on the Mexican Stock Exchange under the trading symbol SRE.MX in May 2021 following an exchange offer launched in the U.S. and Mexico to acquire the then publicly owned shares of IEnova for newly issued shares of our common stock. In November 2024, the CNBV approved our application to cross-list our common stock on the International Quotation System (SIC) of the Mexican Stock Exchange and delist our common stock from the general listing of the Mexican Stock Exchange. Our common stock is no longer quoted or traded on the general listing of the Mexican Stock Exchange or subject to applicable reporting requirements as of December 13, 2024, but remains eligible for trading by Mexican investors on the SIC effective December 16, 2024.

SoCalGas and SDG&E Common Stock

Information concerning dividend declarations for SoCalGas and SDG&E is included in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sources and Uses of Cash – Dividends.”

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

On July 6, 2020, our board of directors authorized the repurchase of shares of our common stock at any time and from time to time in an aggregate amount not to exceed the lesser of $2 billion or amounts spent to purchase no more than 25,000,000 shares. This repurchase authorization was publicly announced on August 5, 2020 and has no expiration date. As of February 25, 2025, a maximum of $1.25 billion and no more than 19,632,529 shares may yet be purchased under this repurchase authorization.

ITEM 6. (RESERVED)

Not applicable.

2024 Form 10-K | 65

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

	Page
Overview	66
Results of Operations by Registrant	67
Sempra	67
SDG&E	77
SoCalGas	80
Capital Resources and Liquidity	82
Critical Accounting Estimates	101
New Accounting Standards	105

OVERVIEW

This combined MD&A includes the operational and financial results of the following three Registrants:

▪Sempra is a California-based holding company with energy infrastructure investments in North America. Our businesses invest in, develop and operate energy infrastructure, and provide electric and gas services to customers.

▪SDG&E is a regulated public utility that provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County.

▪SoCalGas is a regulated public natural gas distribution utility, serving customers throughout most of Southern California and part of central California.

Sempra has the following three reportable segments which reflect how the CODM oversees operational and financial performance:

▪Sempra California

▪Sempra Texas Utilities

▪Sempra Infrastructure

SDG&E and SoCalGas each has one reportable segment.

Below are significant events, including major project updates, that affected our business in 2024 and may continue to affect our future results:

▪In December 2024, we received net proceeds of $1.2 billion from the issuance of 17,142,858 shares of Sempra common stock from the settlement of forward sale agreements entered into in November 2023

▪We established an ATM program providing for the offer and sale of shares of Sempra common stock having an aggregate gross sales price of up to $3.0 billion, and entered into a forward sale agreement under the ATM program for the sale of 2,909,274 shares with net proceeds expected to be approximately $268 million

▪The CPUC approved an FD in the GRC for SDG&E’s and SoCalGas’ revenue requirements for 2024 and attrition year adjustments for 2025 through 2027

▪The CPUC approved an FD to modify the CCM and update SDG&E’s and SoCalGas’ cost of capital effective January 1, 2025

▪The CPUC approved an FD in the SB 380 OII finding that the Aliso Canyon natural gas storage facility is currently necessary for natural gas and electric reliability and affordable rates and closed the OII (subject to future CPUC biennial reviews and potential additional proceedings)

▪The FERC issued an order, which SDG&E has appealed, finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019

▪SDG&E submitted its TO6 filing to the FERC, which the FERC accepted but suspended the effective date to June 1, 2025 and disallowed inclusion of the California ISO adder, which SDG&E has appealed

▪The PUCT approved approximately $2.9 billion of capital expenditures and approximately $520 million of O&M under Oncor’s inaugural system resiliency plan

▪Sempra Infrastructure advanced construction of the ECA LNG Phase 1 project and PA LNG Phase 1 project and entered into an EPC contract with Bechtel for the proposed PA LNG Phase 2 project

▪Sempra Infrastructure commenced commercial operations at its refined products terminal in Topolobampo

2024 Form 10-K | 66

▪Sempra Infrastructure made a positive final investment decision on and began construction of the Cimarrón Wind project

▪We resolved all VAT and legal matters related to and substantially completed liquidation of our equity method investment in RBS Sempra Commodities LLP

RESULTS OF OPERATIONS BY REGISTRANT

Throughout the MD&A, our references to earnings represent earnings attributable to common shares. Variance amounts presented are the after-tax earnings impact (based on applicable statutory tax rates unless otherwise noted) and after NCI but before foreign currency and inflation effects, where applicable.

We discuss herein Sempra’s results of operations and significant changes in earnings, revenues and costs by segment, as well as Parent and other, for the year ended December 31, 2024 compared to the year ended December 31, 2023. For a discussion of our results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to “Part II – Item 7. MD&A – Results of Operations” in our 2023 annual report on Form 10-K filed with the SEC on February 27, 2024. We also discuss herein the impact of foreign currency and inflation rates on Sempra’s results of operations.

RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

(Dollars and shares in millions, except per share amounts)

EARNINGS BY SEGMENT
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra:
Sempra California	$	1,846	$	1,747	$	1,514
Sempra Texas Utilities	781		694		736
Sempra Infrastructure	911		877		310
Segment earnings attributable to common shares	3,538		3,318		2,560
Parent and other	(721)		(288)		(466)
Earnings attributable to common shares	$	2,817	$	3,030	$	2,094

2024 Form 10-K | 67

Sempra California

Sempra California’s earnings are comprised of SDG&E and SoCalGas. Because changes in SDG&E’s and SoCalGas’ cost of natural gas and/or electricity are recovered in rates, changes in these costs are offset in the changes in revenues and therefore do not impact earnings, other than potential impacts related to the GCIM for SoCalGas that we describe below. In addition to the changes in cost or market prices, natural gas or electric revenues recorded during a period are impacted by the difference between customer billings and recorded or CPUC-authorized amounts. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 4 of the Notes to Consolidated Financial Statements.

In 2024 compared to 2023, the increase in earnings of $99 million (6%) to $1.8 billion was primarily due to:

▪$217 million higher income tax benefits primarily from flow-through items, including higher gas repairs tax benefits, offset by $25 million related to income tax benefits in 2023 from previously unrecognized income tax benefits pertaining to gas repairs expenditures

▪$12 million higher electric transmission margin

▪$12 million higher AFUDC equity

▪$11 million higher net regulatory interest income

▪$9 million higher CPUC base operating margin authorized for 2024, net of operating expenses, including higher authorized cost of capital

Offset by:

▪$89 million charge in 2024 for amounts relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019, which we discuss in Note 4 of the Notes to Consolidated Financial Statements

▪$60 million higher net interest expense

▪$15 million impairment from disallowed capital costs in the 2024 GRC FD

Sempra Texas Utilities

In 2024 compared to 2023, the increase in earnings of $87 million (13%) to $781 million was primarily due to higher equity earnings from Oncor Holdings driven by:

▪overall higher revenues primarily attributable to:

◦rate updates to reflect increases in invested capital

◦updates to transmission billing units

◦customer growth

◦base rates implemented in May 2023

Offset by:

◦lower customer consumption primarily attributable to weather

▪write-off of rate base disallowances in 2023 resulting from the PUCT’s final order in Oncor’s comprehensive base rate review

Offset by:

▪higher interest expense and depreciation expense attributable to increases in invested capital

▪higher O&M

2024 Form 10-K | 68

Sempra Infrastructure

In 2024 compared to 2023, the increase in earnings of $34 million (4%) to $911 million was primarily due to:

▪$499 million favorable impact from foreign currency and inflation effects on our monetary positions in Mexico, comprised of a $263 million favorable impact in 2024 compared to a $236 million unfavorable impact in 2023

▪$61 million favorable impact from $19 million net interest income in 2024 compared to $42 million net interest expense in 2023 primarily due to higher capitalization of interest expense in 2024 from projects under construction

▪$47 million favorable impact in interest expense from $30 million unrealized gains in 2024 compared to $17 million unrealized losses in 2023 on interest rate swaps related to the PA LNG Phase 1 project

▪$21 million favorable impact from $20 million income tax benefit in 2024 compared to $1 million income tax expense in 2023 primarily from outside basis differences and remeasurement of deferred taxes

Offset by:

▪$463 million from asset and supply optimization driven by unrealized losses in 2024 compared to unrealized gains in 2023 on commodity derivatives due to changes in natural gas prices and lower LNG diversion fees

▪$79 million from the transportation business driven by lower equity earnings and revenues, including the cumulative impact of new tariffs going into effect in June 2023 for certain pipelines in Mexico and a customer’s early termination of firm transportation agreements in 2023

▪$15 million from the renewables business driven by lower volumes from wind power generation assets

▪$14 million from lower revenues in 2024 offset by higher O&M in 2023 from a provision for expected credit losses on a customer’s past due receivable balance

Parent and Other

In 2024 compared to 2023, the increase in losses of $433 million to $721 million was primarily due to:

▪$330 million income tax expense in 2024 from changes to a valuation allowance against foreign tax credits that were carried forward from the implementation of the Tax Cuts and Jobs Act of 2017

▪$32 million from higher net interest expense

▪$24 million decrease in equity earnings related to our investment in RBS Sempra Commodities LLP due to $16 million in 2024 from the substantial dissolution of the partnership and $40 million in 2023 related to a legal settlement, which we discuss in Notes 5 and 15 of the Notes to Consolidated Financial Statements

▪$23 million income tax benefit in 2023 from the remeasurement of certain deferred income taxes

▪$5 million related to settlement charges from our non-qualified pension plan in 2024

SIGNIFICANT CHANGES IN REVENUES AND COSTS

The regulatory framework permits SDG&E and SoCalGas to recover certain program expenditures and other costs authorized by the CPUC (referred to as “refundable programs”).

Utilities: Natural Gas Revenues and Cost of Natural Gas

Our utilities revenues include natural gas revenues at Sempra California and Sempra Infrastructure, which includes Ecogas. Intercompany revenues are eliminated in Sempra’s Consolidated Statements of Operations.

SDG&E and SoCalGas operate under a regulatory framework that permits the cost of natural gas purchased for core customers to be passed through to customers in rates substantially as incurred and without markup. The GCIM provides for SoCalGas to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between SoCalGas and its core customers. We provide further discussion in Note 3 of the Notes to Consolidated Financial Statements.

2024 Form 10-K | 69

UTILITIES: NATURAL GAS REVENUES AND COST OF NATURAL GAS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra:
Natural gas revenues:
Sempra California	$	7,083	$	9,425	$	7,792
Sempra Infrastructure	78		87		89
Segment totals	7,161		9,512		7,881
Eliminations and adjustments	(20)		(17)		(13)
Total	$	7,141	$	9,495	$	7,868
Cost of natural gas(1):
Sempra California	$	1,118	$	3,747	$	2,562
Sempra Infrastructure	22		8		37
Segment totals	1,140		3,755		2,599
Eliminations and adjustments	(8)		(36)		4
Total	$	1,132	$	3,719	$	2,603

(1)    Excludes depreciation and amortization, which are presented separately on Sempra’s Consolidated Statements of Operations.

In 2024 compared to 2023, Sempra’s natural gas revenues decreased by $2.4 billion (25%) to $7.1 billion driven by Sempra California, which included:

▪$2.6 billion decrease in cost of natural gas sold, which we discuss below

▪$268 million lower revenues from incremental and balanced capital projects that are now in CPUC-authorized revenues as a result of the 2024 GRC FD, offset by higher authorized cost of capital

▪$79 million lower revenues associated with refundable programs, which are fully offset in O&M

▪$31 million lower franchise fee revenues

▪$7 million lower regulatory awards approved by the CPUC

Offset by:

▪$372 million higher CPUC-authorized revenues in 2024, including certain incremental and balanced capital projects that are now in CPUC-authorized revenues as a result of the 2024 GRC FD and higher authorized cost of capital

▪$310 million higher regulatory revenues primarily from the release of a tax regulatory liability for gas repairs expenditures as a result of the 2024 GRC FD

▪$26 million lower regulatory revenues in 2023 from the recognition of previously unrecognized income tax benefits pertaining to gas repairs expenditures, which are offset in income tax expense

In 2024 compared to 2023, Sempra’s cost of natural gas decreased by $2.6 billion to $1.1 billion driven by Sempra California, which included:

▪$2.4 billion lower average natural gas prices

▪$239 million lower volumes driven by weather

Utilities: Electric Revenues and Cost of Electric Fuel and Purchased Power

Our utilities revenues include electric revenues at Sempra California, substantially all of which is at SDG&E. Intercompany revenues are eliminated in Sempra’s Consolidated Statements of Operations.

SDG&E operates under a regulatory framework that permits it to recover the actual cost incurred to generate or procure electricity based on annual estimates of the cost of electricity supplied to customers. The differences in cost between estimates and actual are recovered or refunded in subsequent periods through rates.

2024 Form 10-K | 70

Utility cost of electric fuel and purchased power includes utility-owned generation, power purchased from third parties, and net power purchases and sales to/from the California ISO.

UTILITIES: ELECTRIC REVENUES AND COST OF ELECTRIC FUEL AND PURCHASED POWER
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra:
Electric revenues:
Sempra California	$	4,299	$	4,336	$	4,785
Eliminations and adjustments	(3)		(2)		(2)
Total	$	4,296	$	4,334	$	4,783
Cost of electric fuel and purchased power(1):
Sempra California	$	308	$	445	$	994
Eliminations and adjustments	(63)		(70)		(57)
Total	$	245	$	375	$	937

(1)    Excludes depreciation and amortization, which are presented separately on Sempra’s Consolidated Statements of Operations.

In 2024 compared to 2023, Sempra’s electric revenues decreased by $38 million (1%) remaining at $4.3 billion driven by Sempra California, which included:

▪$176 million lower revenues associated with refundable programs, which are fully offset in O&M

▪$137 million lower cost of electric fuel and purchased power, which we discuss below

▪$94 million charge in 2024 for amounts relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019

▪$18 million lower revenues from a $5 million credit in 2024 compared to a $13 million cost in 2023 for the non-service components of net periodic benefit cost, which fully offsets in other income, net

▪$9 million lower franchise fee revenues

Offset by:

▪$178 million lower ITCs from standalone energy storage projects, which are offset in income tax expense

▪$110 million higher CPUC-authorized revenues in 2024, including certain incremental and balanced capital projects that are now in CPUC-authorized revenues as a result of the 2024 GRC FD and higher authorized cost of capital

▪$82 million higher revenues from incremental and balanced capital projects, including higher authorized cost of capital, offset by certain projects that are now in CPUC-authorized revenues as a result of the 2024 GRC FD

▪$42 million higher revenues from transmission operations

In 2024 compared to 2023, Sempra’s cost of electric fuel and purchased power decreased by $130 million (35%) to $245 million driven by Sempra California, which included:

▪$276 million lower purchased power primarily due to change in excess capacity sales

▪$242 million lower purchased power from the California ISO due to lower market prices

▪$105 million lower utility-owned generation costs

Offset by:

▪$331 million lower sales to the California ISO due to lower market prices

▪$129 million from realized losses in 2024 compared to realized gains in 2023 on derivative contracts for fixed-price natural gas, which are entered into to hedge the cost of electric fuel

2024 Form 10-K | 71

Energy-Related Businesses: Revenues and Cost of Sales

ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra:
Revenues:
Sempra Infrastructure	$	1,804	$	2,984	$	1,830
Parent and other(1)	(56)		(93)		(42)
Total	$	1,748	$	2,891	$	1,788
Cost of sales(2):
Sempra Infrastructure	$	380	$	548	$	942
Total	$	380	$	548	$	942

(1)    Includes eliminations of intercompany activity.

(2)    Excludes depreciation and amortization, which are presented separately on Sempra’s Consolidated Statements of Operations.

In 2024 compared to 2023, Sempra’s revenues from energy-related businesses decreased by $1.1 billion (40%) to $1.7 billion primarily due to:

▪$1.0 billion from asset and supply optimization from contracts to sell natural gas and LNG to third parties, including:

◦$896 million primarily driven by $51 million unrealized losses in 2024 compared to $710 million unrealized gains in 2023 on commodity derivatives and $177 million primarily from lower natural gas prices offset by higher volumes

◦$115 million primarily from lower diversion fees due to lower natural gas prices

▪$55 million lower pipeline transportation revenues primarily from a customer’s early termination of firm transportation agreements in the first quarter of 2023 and lower rates

▪$45 million lower transportation revenues

▪$45 million from TdM mainly due to $78 million from lower power prices offset by $26 million from higher volumes

▪$25 million from lower volumes from wind power generation assets

In 2024 compared to 2023, Sempra’s cost of sales from energy-related businesses decreased by $168 million (31%) to $380 million primarily due to:

▪$99 million at TdM driven by $111 million from lower natural gas prices offset by $11 million from higher volumes

▪$69 million driven by lower natural gas purchases related to asset and supply optimization

Operation and Maintenance

OPERATION AND MAINTENANCE
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra:
Sempra California	$	4,398	$	4,591	$	4,012
Sempra Texas Utilities	5		5		6
Sempra Infrastructure	858		793		656
Segment totals	5,261		5,389		4,674
Parent and other(1)	75		69		72
Total	$	5,336	$	5,458	$	4,746

(1)    Includes eliminations of intercompany activity.

2024 Form 10-K | 72

In 2024 compared to 2023, Sempra’s O&M decreased by $122 million (2%) to $5.3 billion primarily due to:

▪$193 million decrease at Sempra California due to:

◦$255 million lower expenses associated with refundable programs, which costs are recovered in revenue

Offset by:

◦$45 million higher non-refundable operating costs

◦$20 million impairment from disallowed capital costs in the 2024 GRC FD

Offset by:

▪$65 million increase at Sempra Infrastructure due to:

◦$33 million higher development costs and certain non-capitalized expenses from projects under construction

◦$18 million higher purchased services

◦$6 million from a provision for expected credit losses on a customer’s past due receivable balance

Other Income, Net

In 2024 compared to 2023, Sempra’s other income, net, increased by $5 million (4%) to $136 million primarily due to:

▪$17 million higher AFUDC equity, including $12 million at Sempra California

▪$15 million higher net interest income on regulatory balancing accounts at Sempra California

▪$8 million higher net investment gains on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan at Parent and other

▪$5 million lower non-service components of net periodic benefit cost, including $17 million at Sempra California

Offset by:

▪$26 million charge in 2024, comprised of $7 million of AFUDC equity and $19 million of net regulatory interest, relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019

▪$20 million decrease from $14 million losses in 2024 compared to $6 million gains in 2023 from impacts associated with interest rate and foreign exchange instruments and foreign currency transactions primarily at Sempra Infrastructure, including:

◦$18 million lower from $16 million losses in 2024 compared to $2 million gains in 2023 on other foreign currency transactional effects

◦$6 million gains in 2023 on cross-currency swaps as a result of fluctuation of the Mexican peso

We provide further details of the components of other income, net, in Note 1 of the Notes to Consolidated Financial Statements.

Interest Expense

In 2024 compared to 2023, Sempra’s interest expense decreased by $260 million (20%) to $1.0 billion primarily due to:

▪$372 million at Sempra Infrastructure from:

◦$288 million favorable impact in interest expense from interest rate swaps related to the PA LNG Phase 1 project comprised of:

•$245 million from $212 million unrealized gains in 2024 compared to $33 million unrealized losses in 2023

•$43 million from a $29 million settlement in 2024 from the termination of interest rate swaps compared to $14 million settlement losses in 2023 on a contingent interest rate swap

◦$56 million lower interest expense due to higher capitalization of interest expense on projects under construction

Offset by:

▪$66 million at Sempra California from higher debt balances from debt issuances

▪$46 million at Parent and other from higher debt balances from debt issuances, offset by capitalization of interest expense in 2024 on projects under construction at Sempra Infrastructure

2024 Form 10-K | 73

Income Taxes

INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Years ended December 31,
	2024			2023			2022
Sempra:
Income tax expense	$	219		$	490		$	556
Income from continuing operations before income taxes and equity earnings	$	2,110		$	2,627		$	1,343
Equity earnings, before income tax(1)	603			633			666
Pretax income	$	2,713		$	3,260		$	2,009
Effective income tax rate	8		%	15		%	28		%

(1)    We discuss how we recognize equity earnings in Note 5 of the Notes to Consolidated Financial Statements.

We report as part of our pretax results the income or loss attributable to NCI. However, we do not record income taxes for a portion of this income or loss, as some of our entities with NCI are currently treated as partnerships for U.S. income tax purposes, and thus we are only liable for income taxes on the portion of the earnings that are allocated to us. Our pretax income, however, includes 100% of these entities. If our entities with NCI grow, and if we continue to invest in such entities, the impact on our ETR may become more significant.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting for gas repairs expenditures. Sempra elected this change in tax accounting method in its consolidated 2023 income tax return filing.

Sempra records regulatory liabilities for benefits that will be flowed through to customers in the future.

In 2024 compared to 2023, Sempra’s income tax expense decreased by $271 million primarily due to:

▪$619 million from $336 million income tax benefit in 2024 compared to $283 million income tax expense in 2023 from foreign currency and inflation effects on our monetary positions in Mexico

▪lower pretax income

▪$30 million income tax benefit in 2024 from an outside basis difference in a domestic partnership investment

▪$26 million higher income tax benefit from the resolution of prior year income tax items

▪higher income tax benefits from flow-through items, including higher gas repairs tax benefits, offset by $43 million income tax benefit in 2023 from the recognition of previously unrecognized income tax benefits pertaining to gas repairs expenditures

Offset by:

▪$330 million income tax expense in 2024 from changes to a valuation allowance against foreign tax credits that were carried forward from the implementation of the Tax Cuts and Jobs Act of 2017

▪lower income tax benefit in 2024 from lower ITCs from standalone energy storage projects under the IRA

We discuss the impact of foreign currency exchange rates and inflation on income taxes below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.” See Notes 1 and 7 of the Notes to Consolidated Financial Statements for further details about our accounting for income taxes and items subject to flow-through treatment.

2024 Form 10-K | 74

Equity Earnings

In 2024 compared to 2023, Sempra’s equity earnings increased by $128 million (9%) to $1.6 billion primarily due to:

▪$96 million at IMG due to income tax benefit in 2024 compared to an income tax expense in 2023 primarily from foreign currency and inflation effects

▪$86 million at Oncor Holdings driven by:

◦overall higher revenues primarily attributable to:

•rate updates to reflect increases in invested capital

•updates to transmission billing units

•customer growth

•base rates implemented in May 2023

Offset by:

•lower customer consumption primarily attributable to weather

◦write-off of rate base disallowances in 2023 resulting from the PUCT’s final order in Oncor’s comprehensive base rate review

Offset by:

◦higher interest expense and depreciation expense attributable to increases in invested capital

◦higher O&M

Offset by:

▪$24 million at TAG Norte primarily from the cumulative impact of new tariffs going into effect in June 2023 offset by lower income tax expense primarily from foreign currency and inflation effects

▪$21 million related to our investment in RBS Sempra Commodities LLP due to $19 million in 2024 from the substantial dissolution of the partnership and $40 million in 2023 related to a legal settlement

Earnings Attributable to Noncontrolling Interests

In 2024 compared to 2023, Sempra’s earnings attributable to NCI increased by $95 million (17%) to $638 million primarily due to an increase in SI Partners’ net income.

IMPACT OF FOREIGN CURRENCY AND INFLATION RATES ON RESULTS OF OPERATIONS

Because our natural gas distribution utility in Mexico, Ecogas, uses its local currency as its functional currency, its revenues and expenses are translated into U.S. dollars at average exchange rates for the period for consolidation in Sempra’s results of operations.

Foreign Currency Translation

Any difference in average exchange rates used for the translation of income statement activity from year to year can cause a variance in Sempra’s comparative results of operations. In 2024 compared to 2023, the change in our earnings as a result of foreign currency translation rates was negligible.

Transactional Impacts

Although the financial statements of most of our Mexican subsidiaries and JVs have the U.S. dollar as the functional currency, some transactions may be denominated in the local currency; such transactions are remeasured into U.S. dollars. This remeasurement creates transactional gains and losses that are included in other income, net, for our consolidated entities and in equity earnings for our JVs.

We may utilize cross-currency swaps that exchange our Mexican peso-denominated principal and interest payments into the U.S. dollar and swap Mexican fixed interest rates for U.S. fixed interest rates. The impacts of these cross-currency swaps are offset in OCI and are reclassified from AOCI into earnings through other income, net, and interest expense as settlements occur.

2024 Form 10-K | 75

Certain of our Mexican pipelines (namely Los Ramones I and San Fernando at IEnova Pipelines and Los Ramones Norte at TAG Pipelines) generate revenue based on tariffs that are set by government agencies in Mexico, with contracts denominated in Mexican pesos that are indexed to the U.S. dollar, adjusted annually for inflation and fluctuation in the exchange rate. The resultant gains and losses from remeasuring the local currency amounts into U.S. dollars and the offsetting settlement of foreign currency forwards and swaps related to these contracts are included in revenues: energy-related businesses or equity earnings.

Income statement activities at our foreign operations and their JVs are also impacted by transactional gains and losses, a summary of which is shown in the table below:

TRANSACTIONAL GAINS (LOSSES) FROM FOREIGN CURRENCY AND INFLATION EFFECTS
(Dollars in millions)
	Total reported amounts						Transactional (losses) gains included in reported amounts
	Years ended December 31,
	2024		2023		2022		2024		2023		2022
Sempra:
Other income, net	$	136	$	131	$	24	$	(14)	$	6	$	(13)
Income tax expense	(219)		(490)		(556)		336		(283)		(169)
Equity earnings	1,609		1,481		1,498		64		(68)		(36)
Net income	3,500		3,618		2,285		386		(345)		(218)
Earnings attributable to noncontrolling interests	(638)		(543)		(146)		(124)		110		54
Earnings attributable to common shares	2,817		3,030		2,094		262		(235)		(164)

Foreign Currency Exchange Rate and Inflation Impacts on Income Taxes and Related Hedging Activity

Our Mexican subsidiaries have U.S. dollar-denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that are affected by Mexican currency exchange rate movements for Mexican income tax purposes. They also have significant deferred income tax assets and liabilities denominated in the Mexican peso that must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. As a result, fluctuations in both the currency exchange rate for the Mexican peso against the U.S. dollar and Mexican inflation may expose us to fluctuations in income tax expense, other income, net, and equity earnings. We may use foreign currency derivatives as a means to help manage exposure to the currency exchange rate on our monetary assets and liabilities, and this derivative activity impacts other income, net. However, we generally do not hedge our deferred income tax assets and liabilities, which makes us susceptible to volatility in income tax expense caused by exchange rate fluctuations and inflation.

2024 Form 10-K | 76

We discuss herein SDG&E’s results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2024 compared to the year ended December 31, 2023. For a discussion of SDG&E’s results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to “Part II – Item 7. MD&A – Results of Operations” in our 2023 annual report on Form 10-K filed with the SEC on February 27, 2024.

RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

(Dollars in millions)

In 2024 compared to 2023, the decrease in SDG&E’s earnings of $45 million (5%) to $891 million was primarily due to:

▪$89 million charge in 2024 for amounts relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019

▪$32 million higher net interest expense

▪$6 million lower AFUDC equity

Offset by:

▪$33 million higher income tax benefits primarily from flow through items, including higher gas repairs tax benefits

▪$27 million higher CPUC base operating margin authorized for 2024, net of operating expenses, including higher authorized cost of capital

▪$12 million higher electric transmission margin

▪$10 million lower Wildfire Fund amortization

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SIGNIFICANT CHANGES IN REVENUES AND COSTS

Electric Revenues and Cost of Electric Fuel and Purchased Power

In 2024 compared to 2023, SDG&E’s electric revenues decreased by $36 million (1%) remaining at $4.3 billion primarily due to:

▪$176 million lower revenues associated with refundable programs, which are fully offset in O&M

▪$137 million lower cost of electric fuel and purchased power, which we discuss below

▪$94 million charge in 2024 for amounts relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019

▪$18 million lower revenues from a $5 million credit in 2024 compared to a $13 million cost in 2023 for the non-service components of net periodic benefit cost, which fully offsets in other income, net

▪$9 million lower franchise fee revenues

Offset by:

▪$178 million lower ITCs from standalone energy storage projects, which are offset in income tax (expense) benefit

▪$110 million higher CPUC-authorized revenues in 2024, including certain incremental and balanced capital projects that are now in CPUC-authorized revenues as a result of the 2024 GRC FD and higher authorized cost of capital

▪$82 million higher revenues from incremental and balanced capital projects, including higher authorized cost of capital, offset by certain projects that are now in CPUC-authorized revenues as a result of the 2024 GRC FD

▪$42 million higher revenues from transmission operations

In 2024 compared to 2023, SDG&E’s cost of electric fuel and purchased power decreased by $137 million (31%) to $308 million primarily due to:

▪$276 million lower purchased power primarily due to change in excess capacity sales

▪$242 million lower purchased power from the California ISO due to lower market prices

▪$105 million lower utility-owned generation costs

Offset by:

▪$331 million lower sales to the California ISO due to lower market prices

▪$129 million from realized losses in 2024 compared to realized gains in 2023 on derivative contracts for fixed-price natural gas, which are entered into to hedge the cost of electric fuel

Natural Gas Revenues and Cost of Natural Gas

SDG&E’s average cost of natural gas per thousand cubic feet was $5.41 in 2024 and $11.05 in 2023. The average cost of natural gas sold at SDG&E is impacted by market prices, as well as transportation, tariff and other charges.

In 2024 compared to 2023, SDG&E’s natural gas revenues decreased by $220 million (18%) to $1.0 billion primarily due to:

▪$290 million decrease in cost of natural gas sold, which we discuss below

▪$38 million lower revenues from incremental and balanced capital projects that are now in CPUC-authorized revenues as a result of the 2024 GRC FD, offset by higher authorized cost of capital

▪$7 million lower franchise fee revenues

Offset by:

▪$57 million higher regulatory revenues primarily from the release of a tax regulatory liability for gas repairs expenditures as a result of the 2024 GRC FD

▪$55 million higher CPUC-authorized revenues in 2024, including certain incremental and balanced capital projects that are now in CPUC-authorized revenues as a result of the 2024 GRC FD and higher authorized cost of capital

▪$11 million higher revenues associated with refundable programs, which are fully offset in O&M

In 2024 compared to 2023, SDG&E’s cost of natural gas decreased by $290 million to $242 million primarily due to:

▪$252 million lower average natural gas prices

▪$38 million lower volumes driven by weather

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Operation and Maintenance

In 2024 compared to 2023, SDG&E’s O&M decreased by $154 million (8%) to $1.7 billion due to:

▪$165 million lower expenses associated with refundable programs, which costs are recovered in revenue

Offset by:

▪$14 million higher non-refundable operating costs

Other Income, Net

In 2024 compared to 2023, SDG&E’s other income, net, decreased by $7 million (7%) to $90 million primarily due to:

▪$26 million charge in 2024, comprised of $7 million of AFUDC equity and $19 million of net regulatory interest, relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019

▪$6 million lower AFUDC equity

Offset by:

▪$23 million increase from a $4 million credit in 2024 compared to $19 million cost in 2023 for the non-service components of net periodic benefit cost

Interest Expense

In 2024 compared to 2023, SDG&E’s interest expense increased by $28 million (6%) to $525 million from higher debt balances from debt issuances.

Income Taxes

INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Years ended December 31,
	2024			2023			2022
SDG&E:
Income tax expense (benefit)	$	153		$	(26)		$	182
Income before income taxes	$	1,044		$	910		$	1,097
Effective income tax rate	15		%	(3)		%	17		%

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting for gas repairs expenditures. SDG&E elected this change in tax accounting method in Sempra’s consolidated 2023 income tax return filing.

SDG&E records regulatory liabilities for benefits that will be flowed through to customers in the future.

In 2024 compared to 2023, SDG&E had an income tax expense in 2024 compared to income tax benefit in 2023 primarily due to lower income tax benefit in 2024 from lower ITCs from standalone energy storage projects under the IRA and higher pretax income.

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We discuss herein SoCalGas’ results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2024 compared to the year ended December 31, 2023. For a discussion of SoCalGas’ results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to “Part II – Item 7. MD&A – Results of Operations” in our 2023 annual report on Form 10-K filed with the SEC on February 27, 2024.

RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

(Dollars in millions)

In 2024 compared to 2023, the increase in SoCalGas’ earnings of $144 million (18%) to $955 million was primarily due to:

▪$184 million higher income tax benefits primarily from flow-through items, including higher gas repairs tax benefits, offset by $25 million related to income tax benefits in 2023 from previously unrecognized income tax benefits pertaining to gas repairs expenditures

▪$18 million higher AFUDC equity

▪$11 million higher net regulatory interest income

Offset by:

▪$28 million higher net interest expense

▪$18 million lower CPUC base operating margin authorized for 2024, net of operating expenses, offset by higher authorized cost of capital

▪$15 million impairment from disallowed capital costs in the 2024 GRC FD

▪$5 million lower regulatory awards approved by the CPUC

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SIGNIFICANT CHANGES IN REVENUES AND COSTS

Natural Gas Revenues and Cost of Natural Gas

SoCalGas’ average cost of natural gas per thousand cubic feet was $3.28 in 2024 and $10.47 in 2023. The average cost of natural gas sold at SoCalGas is impacted by market prices, as well as transportation and other charges.

In 2024 compared to 2023, SoCalGas’ natural gas revenues decreased by $2.1 billion (25%) to $6.2 billion primarily due to:

▪$2.3 billion decrease in cost of natural gas sold, which we discuss below

▪$230 million lower revenues from incremental and balanced capital projects that are now in CPUC-authorized revenues as a result of the 2024 GRC FD, offset by higher authorized cost of capital

▪$90 million lower revenues associated with refundable programs, which are fully offset in O&M

▪$24 million lower franchise fee revenues

▪$7 million lower regulatory awards approved by the CPUC

Offset by:

▪$317 million higher CPUC-authorized revenues in 2024, including certain incremental and balanced capital projects that are now in CPUC-authorized revenues as a result of the 2024 GRC FD and higher authorized cost of capital

▪$253 million higher regulatory revenues primarily from the release of a tax regulatory liability for gas repairs expenditures as a result of the 2024 GRC FD

▪$26 million lower regulatory revenues in 2023 from the recognition of previously unrecognized income tax benefits pertaining to gas repairs expenditures, which are offset in income tax (expense) benefit

▪$6 million higher revenues from higher non-service components of net periodic benefit cost, which fully offsets in other income (expense), net

In 2024 compared to 2023, SoCalGas’ cost of natural gas decreased by $2.3 billion to $959 million primarily due to:

▪$2.1 billion lower average natural gas prices

▪$201 million lower volumes driven by weather

Operation and Maintenance

In 2024 compared to 2023, SoCalGas’ O&M decreased by $30 million (1%) remaining at $2.8 billion due to:

▪$90 million lower expenses associated with refundable programs, which costs are recovered in revenue

Offset by:

▪$40 million higher non-refundable operating costs

▪$20 million impairment from disallowed capital costs in the 2024 GRC FD

Other Income (Expense), Net

In 2024 compared to 2023, SoCalGas’ other income, net, was $25 million compared to other expense, net, of $4 million primarily due to:

▪$18 million higher AFUDC equity

▪$15 million higher net interest income on regulatory balancing accounts

Offset by:

▪$6 million higher non-service components of net periodic benefit cost

Interest Expense

In 2024 compared to 2023, SoCalGas’ interest expense increased by $38 million (13%) to $323 million from higher debt balances from debt issuances.

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Income Taxes

INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Years ended December 31,
	2024			2023			2022
SoCalGas:
Income tax expense (benefit)	$	31		$	(5)		$	138
Income before income taxes	$	987		$	807		$	738
Effective income tax rate	3		%	(1)		%	19		%

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting for gas repairs expenditures. SoCalGas elected this change in tax accounting method in Sempra’s consolidated 2023 income tax return filing.

SoCalGas records regulatory liabilities for benefits that will be flowed through to customers in the future.

In 2024 compared to 2023, SoCalGas had an income tax expense in 2024 compared to income tax benefit in 2023 primarily due to:

▪higher pretax income

Offset by:

▪$40 million higher income tax benefit from the resolution of prior year income tax items

▪higher income tax benefits from flow-through items, including higher gas repairs tax benefits, offset by $43 million income tax benefit in 2023 from the recognition of previously unrecognized income tax benefits pertaining to gas repairs expenditures

CAPITAL RESOURCES AND LIQUIDITY

OVERVIEW

Sempra

Liquidity

We expect to meet our cash requirements through cash flows from operations, unrestricted cash and cash equivalents, borrowings under or supported by our credit facilities, other incurrences of debt which may include issuing debt securities and obtaining term loans, issuing equity securities under our ATM program or other offerings, and other financing transactions which may include, distributions from our equity method investments, project financing and funding from NCI owners. We believe that these cash flow sources, combined with available funds, will be adequate to fund our operations in both the short-term and long-term, including to:

▪finance capital expenditures

▪repay debt

▪fund dividends

▪fund contractual and other obligations and otherwise meet liquidity requirements

▪fund capital contribution requirements

▪fund new business or asset acquisitions

Sempra, SDG&E and SoCalGas currently have reasonable access to the money markets and capital markets and are not currently constrained in their ability to borrow or otherwise raise money at market rates from commercial banks, under existing revolving credit facilities, through public offerings of debt or equity securities (including under our ATM program or other offerings), or through private placements of debt supported by our revolving credit facilities in the case of commercial paper. However, our ability to access these markets or obtain credit from commercial banks outside of our committed revolving credit facilities could become materially constrained if economic conditions worsen or disruptions to or volatility in these markets increase. In addition, our financing activities, actions by credit rating agencies and prevailing interest rates, as well as many other factors, could negatively affect the availability and cost of both short-term and long-term debt and equity financing. In January 2025, S&P revised Sempra’s outlook to negative from stable and downgraded SoCalGas’ issuer credit rating to A- from A. Also, cash flows

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from operations may be impacted by the timing and outcomes of regulatory proceedings, commencement and completion of, and potential cost overruns for, large projects and other material events. If cash flows from operations were to be significantly reduced or we were unable to borrow or obtain other financing under acceptable terms, we would likely first reduce or postpone discretionary capital expenditures (not related to safety/reliability) and investments in new businesses. We monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our goal to maintain our investment-grade credit ratings.

Common Stock Offering and ATM Program

In December 2024, upon full physical settlement of forward sale agreements entered into in connection with our November 2023 common stock offering, we received net proceeds of $1.2 billion from the issuance of 17,142,858 shares of Sempra common stock.

In November 2024, we established an ATM program providing for the offer and sale of shares of Sempra common stock having an aggregate gross sales price of up to $3.0 billion through agents acting as our sales agents or as forward sellers or directly to the agents as principals. The shares may be offered and sold in amounts and at times to be determined by us from time to time. At December 31, 2024, approximately $2.7 billion of common stock remained available for sale under the ATM program, which reflects the forward sale agreement that we describe below.

In November 2024, we entered into a forward sale agreement under the ATM program for the sale of 2,909,274 shares of Sempra common stock. We did not initially receive any proceeds from the sale of shares pursuant to this forward sale agreement. At December 31, 2024, a total of 2,909,274 shares of Sempra common stock remain subject to future settlement under this forward sale agreement, which may be settled on one or more dates specified by us occurring no later than June 30, 2026, which is the final settlement date under the agreement. At the initial forward price of $92.1546 per share, we expect that the net proceeds from the full physical settlement of the forward sale agreement would be approximately $268 million (net of sales commissions of approximately $2 million, but before deducting equity issuance costs, and subject to certain adjustments pursuant to the forward sale agreements). Although we expect to settle the forward sale agreement entirely by the physical delivery of shares of our common stock in exchange for cash proceeds, we may, subject to certain conditions, elect cash settlement or net share settlement for all or a portion of our obligations under the forward sale agreement. The forward sale agreement is also subject to acceleration by the forward purchaser upon the occurrence of certain events.

We further discuss these activities, including the use of proceeds, in Note 12 of the Notes to Consolidated Financial Statements.

Available Funds

Our committed lines of credit provide liquidity and support commercial paper. Sempra, SDG&E and SoCalGas each has a committed line of credit expiring in 2029 and Sempra Infrastructure has four committed lines of credit expiring on various dates from 2025 through 2030, and an uncommitted line of credit expiring in 2026.

AVAILABLE FUNDS AT DECEMBER 31, 2024
(Dollars in millions)
	Sempra		SDG&E		SoCalGas
Unrestricted cash and cash equivalents(1)	$	1,565	$	—	$	12
Available unused credit(2)	8,620		1,083		863

(1)    Amounts at Sempra include $70 held in non-U.S. jurisdictions. We discuss repatriation in Note 7 of the Notes to Consolidated Financial Statements.

(2)    Available unused credit is the total available on committed and uncommitted lines of credit that we discuss in Note 6 of the Notes to Consolidated Financial Statements. Because our commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding and any letters of credit outstanding as a reduction to the available unused credit.

Short-Term Borrowings

We use short-term debt primarily to meet liquidity requirements, fund shareholder dividends, and temporarily finance capital expenditures or acquisitions. SDG&E and SoCalGas use short-term debt primarily to meet working capital needs or to help fund event-specific costs. Commercial paper, a term loan and lines of credit were our primary sources of short-term debt funding in 2024.

We discuss our short-term debt activities in Note 6 of the Notes to Consolidated Financial Statements and below in “Sources and Uses of Cash.”

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The following table shows selected statistics for our commercial paper borrowings.

COMMERCIAL PAPER STATISTICS
(Dollars in millions)
	Sempra						SDG&E						SoCalGas
	December 31,
	2024			2023			2024			2023			2024			2023
Amount outstanding at period end	$	754		$	1,313		$	417		$	—		$	337		$	947
Weighted-average interest rate at period end	4.67		%	5.48		%	4.76		%	—		%	4.56		%	5.44		%
Daily weighted-average outstanding balance	$	1,320		$	1,329		$	161		$	48		$	313		$	301
Daily weighted-average yield	4.74		%	5.02		%	2.46		%	1.00		%	4.98		%	4.24		%
Maximum daily amount outstanding	$	2,503		$	2,119		$	696		$	408		$	966		$	982

Long-Term Debt Activities

Significant issuances of and payments on long-term debt in 2024 included the following:

LONG-TERM DEBT ISSUANCES AND PAYMENTS
(Dollars in millions)
Issuances:	Amount at issuance		Maturity
Sempra 6.40% junior subordinated notes	$	1,250	2054
Sempra 6.875% junior subordinated notes	600		2054
Sempra 6.875% junior subordinated notes	500		2054
Sempra 6.55% junior subordinated notes	600		2055
Sempra 6.625% junior subordinated notes	400		2055
SDG&E 5.55% first mortgage bonds	600		2054
SoCalGas 5.05% first mortgage bonds	600		2034
SoCalGas 5.60% first mortgage bonds	500		2054
Sempra Infrastructure variable rate notes (ECA LNG Phase 1 project)	231		2025
Sempra Infrastructure variable rate notes (PA LNG Phase 1 project)	832		2030
Payments:	Payments		Maturity
SDG&E variable rate term loan	$	400	2024
SoCalGas 3.15% first mortgage bonds	500		2024

At December 31, 2024, Sempra expects to make interest payments on long-term debt totaling $27.2 billion, of which $1.5 billion is expected to be paid in 2025 and $25.7 billion is expected to be paid in subsequent years through 2079. At December 31, 2024, SDG&E expects to make interest payments on long-term debt totaling $6.7 billion, of which $400 million is expected to be paid in 2025 and $6.3 billion is expected to be paid in subsequent years through 2054. At December 31, 2024, SoCalGas expects to make interest payments on long-term debt totaling $5.6 billion, of which $300 million is expected to be paid in 2025 and $5.3 billion is expected to be paid in subsequent years through 2054. We calculate expected interest payments using the stated interest rate for fixed-rate obligations, including floating-to-fixed interest rate swaps. We calculate expected interest payments for variable-rate obligations based on forecasted rates in effect at December 31, 2024.

We discuss our long-term debt activities, including the use of proceeds on long-term debt issuances, and maturities in Note 6 of the Notes to Consolidated Financial Statements.

Credit Ratings

The issuer credit ratings of Sempra, SDG&E and SoCalGas remained at investment grade levels in 2024.

ISSUER CREDIT RATINGS AT DECEMBER 31, 2024
	Sempra	SDG&E	SoCalGas
Moody’s	Baa2 with a stable outlook	A3 with a stable outlook	A2 with a stable outlook
S&P	BBB+ with a stable outlook	BBB+ with a stable outlook	A with a negative outlook
Fitch	BBB+ with a stable outlook	BBB+ with a stable outlook	A with a stable outlook

On January 9, 2025, S&P affirmed Sempra’s issuer credit rating and revised Sempra’s outlook to negative from stable. At the same time, S&P downgraded SoCalGas’ issuer credit rating to A- from A and revised SoCalGas’ outlook to stable from negative.

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Downgrades of or other negative actions with respect to Sempra’s or any of its subsidiaries’ credit ratings or rating outlooks may, depending on the severity, result in the imposition of financial or other burdensome covenants or a requirement for collateral to be posted in the case of certain financing arrangements and may materially and adversely affect the market prices of their equity and debt securities, the rates at which borrowings are made and commercial paper is issued, and the various fees on their outstanding credit facilities. This could make it more costly for Sempra, SDG&E, SoCalGas and Sempra’s other subsidiaries to issue debt or equity securities, to borrow under credit facilities and to raise certain other types of financing. We provide additional information about our credit ratings at Sempra, SDG&E and SoCalGas in “Part I – Item 1A. Risk Factors.”

Sempra has agreed that, if the credit rating of Oncor’s senior secured debt by any of the Rating Agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT. Oncor’s senior secured debt was rated A2, A+ and A at Moody’s, S&P and Fitch, respectively, at December 31, 2024.

Sempra, SDG&E and SoCalGas have committed lines of credit to provide liquidity and to support commercial paper. Borrowings under these facilities bear interest at benchmark rates plus a margin that varies with market index rates and each borrower’s credit rating. Each facility also requires a commitment fee on available unused credit that may be impacted by each borrower’s credit rating. For example, assuming a one-notch downgrade:

▪If Sempra were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 25 bps. The commitment fee on available unused credit would also increase 5 bps.

▪If SDG&E were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 12.5 bps. The commitment fee on available unused credit would also increase 5 bps.

▪If SoCalGas were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 12.5 bps. The commitment fee on available unused credit would also increase 2.5 bps.

Sempra’s, SDG&E’s and SoCalGas’ credit ratings also may affect their respective credit limits related to derivative instruments, as we discuss in Note 9 of the Notes to Consolidated Financial Statements.

Loans due to/from Affiliates

At December 31, 2024, Sempra had $352 million in loans due to unconsolidated affiliates.

Postretirement Benefits

Sempra, SDG&E and SoCalGas have significant investments in several trusts to provide for future payments of pensions and PBOP. The trusts’ ability to make ongoing required benefit payments has not been materially adversely affected by changes in asset values, which are dependent on market fluctuations, contributions and withdrawals. However, changes in asset values or other factors in future periods (such as changes to discount rates, assumed rates of return, mortality tables and regulations) may impact funding requirements for pension and PBOP plans. Additionally, contributions to our plans are based on our funding policy, which generally limits payments from exceeding plan assets of 110% of the projected benefit obligation, which are subject to maximum income tax deduction limitations. Sempra, SDG&E and SoCalGas expect to contribute $283 million, $55 million and $189 million, respectively, to pension and PBOP plans in 2025 and $1.5 billion, $480 million and $768 million, respectively, in the nine years thereafter. At SDG&E and SoCalGas, funding requirements are generally recoverable in rates. We discuss our employee benefit plans and our expected contributions to those plans in Note 8 of the Notes to Consolidated Financial Statements.

Pillar Two

The Organization for Economic Cooperation and Development has introduced a framework known as “Pillar Two” to implement a global minimum effective tax rate of 15% in every jurisdiction (generally, every country) in which a company does business. Many aspects of the Pillar Two framework became effective beginning in 2024. While it is uncertain whether the U.S. or Mexico will enact legislation to adopt the Pillar Two framework, other countries are in the process of introducing and enacting legislation to implement Pillar Two. We do not currently expect the Pillar Two framework to have a material effect on Sempra’s, SDG&E’s or SoCalGas’ results of operations, financial condition and/or cash flows.

Sempra California

SDG&E’s and SoCalGas’ operations have historically provided relatively stable earnings and liquidity. Their future performance and liquidity will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by legislatures, litigation and the changing energy marketplace, as well as other matters described in this report. SDG&E and SoCalGas expect that the available unused funds from their credit facilities described above, which also supports their commercial paper programs, cash flows from operations, and other incurrences of debt including issuing debt securities and

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obtaining term loans will continue to be adequate to fund their respective current operations and planned capital expenditures. SDG&E and SoCalGas manage their capital structures and pay dividends when appropriate and as approved by their respective boards of directors.

The implementation of customer assistance programs and higher 2023 winter season customer billings have resulted in certain SDG&E and SoCalGas customers exhibiting slower payment and higher levels of nonpayment than has been the case historically.

SDG&E and SoCalGas have regulatory mechanisms to recover credit losses and thus record changes in the allowances for credit losses related to Accounts Receivable – Trade that are probable of recovery in regulatory accounts. Although SDG&E and SoCalGas have regulatory mechanisms to recover credit losses, delay in payments by customers impacts the timing of their cash flows.

As we discuss in Note 4 of the Notes to Consolidated Financial Statements, changes in regulatory balancing accounts for significant costs at SDG&E and SoCalGas, particularly a change between over and undercollected status, may have a significant impact on cash flows. These changes generally represent the difference between when costs are incurred and when they are ultimately recovered or refunded in rates through billings to customers.

CPUC GRC

2024 Revenue Requirements and Attrition Year Revenues. In December 2024, the CPUC approved an FD in the 2024 GRC for SDG&E and SoCalGas that authorizes SDG&E’s and SoCalGas’ revenue requirements for 2024 and attrition year adjustments for 2025 through 2027, inclusively.

The GRC FD adopts a 2024 revenue requirement of $2,699 million for SDG&E’s combined operations ($2,193 million for its electric operations and $506 million for its natural gas operations), which represents an increase of $189 million (7.5%) over its authorized 2023 combined revenue requirement. The GRC FD also specifies an increase in SDG&E’s 2025, 2026, and 2027 combined revenue requirements of $147 million (5.45%), $119 million (4.17%) and $122 million (4.11%), respectively, over the preceding year’s combined revenue requirement, all of which will be updated to implement a previously authorized change in the cost of capital that we describe below that adjusted SDG&E’s rate of return to 7.45%.

The GRC FD adopts a 2024 revenue requirement of $3,806 million for SoCalGas, which represents an increase of $324 million (9.3%) over its authorized 2023 revenue requirement. The GRC FD also specifies an increase in SoCalGas’ 2025, 2026, and 2027 revenue requirements of $190 million (5.00%), $116 million (2.91%) and $120 million (2.92%), respectively, over the preceding year’s revenue requirement, all of which will be updated to implement a previously authorized change in the cost of capital that we describe below that adjusted SoCalGas’ rate of return to 7.49%.

Since the GRC FD is effective retroactive to January 1, 2024, SDG&E and SoCalGas recorded the retroactive impacts in the fourth quarter of 2024. The incremental revenue requirements associated with the period from January 1, 2024 through January 31, 2025 are being recovered in rates over an 18-month period that began on February 1, 2025.

Existing and Anticipated Requests for Recovery of Specified Safety, Maintenance and Reliability Investments. The GRC also provides SDG&E and SoCalGas with numerous mechanisms to seek cost recovery of specified projects and programs. We expect that the requests for cost recovery of these projects and programs, which remain subject to CPUC approval, will result in additional amounts of authorized revenue requirement that are not included in the amounts described above. These projects and programs include (i) the Track 2 and Track 3 requests related to SDG&E’s wildfire mitigation plan costs that we describe below, as well as review of SoCalGas’ and SDG&E’s Pipeline Safety Enhancement Plan costs incurred from 2015 to 2020, inclusively, which the GRC FD added to the Track 3 request, (ii) the ability to file advice letters to implement the revenue requirements associated with the costs of SDG&E’s Moreno compressor station project and SoCalGas’ Honor Rancho compressor station and customer information system replacement projects, which projects were all approved by the CPUC subject to applicable cost caps, and (iii) the opportunity to file separate applications for cost recovery of mobile home park and gas integrity management programs at both SDG&E and SoCalGas, advanced metering infrastructure replacements at SDG&E, and other projects and programs.

CCM

A CPUC cost of capital proceeding every three years determines a utility’s authorized capital structure and authorized return on rate base. The CCM applies in the interim years and considers changes in the cost of capital based on changes in interest rates based on the applicable utility bond index published by Moody’s (CCM benchmark rate) for each 12-month period ending September 30 (the measurement period). Alternatively, each of SDG&E and SoCalGas is permitted to file a cost of capital application to have its cost of capital determined in lieu of the CCM in an interim year in which an extraordinary or catastrophic event materially impacts its cost of capital and affects utilities differently than the market as a whole. In October 2024, the CPUC

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issued an FD to modify the CCM. The FD updates the upward or downward adjustment to authorized ROE, if the CCM is triggered, from 50% to 20% of the change in the benchmark rate during the measurement period. The FD adopted this change effective January 1, 2025, reducing both SDG&E’s and SoCalGas’ ROE by 42 bps to 10.23% and 10.08%, respectively, and allowing SDG&E and SoCalGas to update their respective costs of preferred equity and debt for 2025.

SDG&E

Wildfire Fund

The carrying value of SDG&E’s Wildfire Fund asset totaled $276 million at December 31, 2024. We describe the Wildfire Legislation and SDG&E’s commitment to make annual shareholder contributions to the Wildfire Fund through 2028 in Note 1 of the Notes to Consolidated Financial Statements.

SDG&E is exposed to the risk that the participating California electric IOUs may incur third-party wildfire costs for which they will seek recovery from the Wildfire Fund with respect to wildfires that have occurred since enactment of the Wildfire Legislation in July 2019. In such a situation, SDG&E may recognize a reduction of its Wildfire Fund asset and record accelerated amortization against earnings when available coverage is reduced due to recoverable claims from any of the participating IOUs. PG&E is seeking reimbursement from the Wildfire Fund for losses associated with the Dixie Fire, which burned from July 2021 through October 2021. In the case of the recent LA fires, the causes of these fires have not been determined and therefore these fires may not impact the Wildfire Fund. If any California electric IOUs’ assets are determined to be a cause of fires, including fires of the size and scope of the recent LA Fires, payments of claims associated with those events could have a material adverse effect on the Wildfire Fund and on SDG&E’s and Sempra’s financial condition and results of operations up to the carrying value of our Wildfire Fund asset, with additional potential material exposure if SDG&E’s equipment is determined to be a cause of a fire. In addition, the Wildfire Fund could be completely exhausted due to fires in the other California electric IOUs’ service territories, by fires in SDG&E’s service territory or by a combination thereof. In the event that the Wildfire Fund is materially diminished, exhausted or terminated, SDG&E will lose the protection afforded by the Wildfire Fund, and as a consequence, a fire in SDG&E’s service territory could have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Wildfire Mitigation Cost Recovery Mechanism

2024 GRC Track 2. In October 2023, SDG&E submitted a separate request to the CPUC in its 2024 GRC, known as a Track 2 request. This request seeks review and recovery of $1.5 billion of wildfire mitigation plan costs incurred from 2019 through 2022 that were in addition to amounts authorized in the 2019 GRC and not addressed in the 2024 GRC FD. SDG&E expects to receive a proposed decision for its Track 2 request in the first half of 2025.

Revenue requirements associated with the Track 2 request have been recorded in a regulatory account. In February 2024, the CPUC approved an interim cost recovery mechanism that permits SDG&E to recover in rates $194 million and $96 million of this regulatory account balance in 2024 and 2025, respectively. Such recovery of SDG&E’s wildfire mitigation plan regulatory account balance will be subject to refund, contingent on the reasonableness review decision for its Track 2 request.

2024 GRC Track 3. SDG&E expects to submit in the first half of 2025 an additional request to the CPUC in its 2024 GRC, known as a Track 3 request, for review and recovery of wildfire mitigation plan costs incurred in 2023.

FERC Rate Matters

SDG&E files separately with the FERC for its authorized transmission revenue requirement and ROE on FERC-regulated electric transmission operations and assets.

SDG&E’s authorized TO5 settlement provided for an ROE of 10.60%, consisting of a base ROE of 10.10% plus the California ISO adder. In December 2024, the FERC issued an order, which SDG&E has appealed, finding that SDG&E is not eligible for the California ISO adder and that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019. In June 2024, SDG&E exercised its right to terminate the TO5 settlement. Accordingly, in October 2024, SDG&E submitted its TO6 filing to the FERC, requested to be effective January 1, 2025, and subject to refund. SDG&E’s TO6 filing proposes, among other items, an increase to SDG&E’s currently authorized base ROE from 10.10% to 11.75% plus the California ISO adder, for a total ROE of 12.25%. In December 2024, the FERC accepted SDG&E’s TO6 filing but suspended the effective date to June 1, 2025 and disallowed the inclusion of the California ISO adder, which SDG&E has appealed.

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SONGS Decommissioning

SDG&E has significant investments in the SONGS NDT to provide for future payments of nuclear decommissioning. The NDT’s ability to make ongoing required payments has not been materially or adversely affected by changes in asset values, which are dependent on market fluctuations, contributions and withdrawals. However, asset values could be materially and adversely affected by future activity in the equity and fixed income markets, and changes in the estimated decommissioning costs, or in the assumptions and judgments made by management underlying these estimates, could cause revisions to the estimated total cost associated with retiring the assets. Funding requirements are generally recoverable in rates. We discuss SDG&E’s NDT and its expected SONGS decommissioning payments in Note 14 of the Notes to Consolidated Financial Statements.

Off-Balance Sheet Arrangements

SDG&E has entered into PPAs and tolling agreements that are variable interests in unconsolidated entities. We discuss variable interests in Note 1 of the Notes to Consolidated Financial Statements.

SoCalGas

LA Fires

The LA Fires burned in SoCalGas’ service territory. As of February 6, 2025, the California Department of Forestry and Fire Protection estimated that the Palisades and Eaton fires damaged approximately 2,000 structures and destroyed approximately 16,200 structures.

The potential costs to SoCalGas will depend on various factors, including the number of customers impacted and the nature and extent of damage to SoCalGas’ facilities. Due to the limited amount of time that has elapsed since the start of the LA Fires and the limited available information, including continued uncertainty as to the magnitude of their impacts on customers and utility facilities, SoCalGas cannot reasonably estimate the amount or range of such potential costs at this time.

SoCalGas has mechanisms available for potential recovery of costs associated with declared disasters, such as the LA Fires, including through insurance and customer rates. Failure by SoCalGas to timely recover all or a substantial portion of its costs related to the LA Fires or any conclusion that such recovery is no longer probable could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Aliso Canyon Natural Gas Storage Facility

Litigation. From October 23, 2015 through February 11, 2016, SoCalGas experienced the Leak, which we describe in Note 15 of the Notes to Consolidated Financial Statements and in “Part I – Item 1A. Risk Factors.” As of February 19, 2025, there are approximately 520 plaintiffs who have filed lawsuits related to the Leak or who declined to participate in a previous settlement related to the Leak and are able to continue to pursue their claims. SoCalGas’ loss contingency accruals do not include any amounts in excess of what has been reasonably estimated to resolve these matters, nor any amounts that may be necessary to resolve threatened litigation, other potential litigation or other costs. We are not able to reasonably estimate the possible loss or a range of possible losses in excess of the amounts accrued, which could be significant and could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Operations and Reliability. Natural gas withdrawn from storage is important to help maintain service reliability during peak demand periods, including consumer heating needs in the winter and peak electric generation needs in the summer. The Aliso Canyon natural gas storage facility is the largest SoCalGas storage facility and an important component of SoCalGas’ delivery system. In December 2024, the CPUC approved an FD in the SB 380 OII finding that the Aliso Canyon natural gas storage facility is currently necessary for natural gas and electric reliability and affordable rates and closed the OII. Among other things, and subject to future CPUC biennial reviews and potential additional proceedings, the FD authorizes the Aliso Canyon natural gas storage facility to continue operating and sets the maximum working natural gas storage level at 68.6 bcf.

At December 31, 2024, the Aliso Canyon natural gas storage facility had a net book value of $1.0 billion. If the Aliso Canyon natural gas storage facility were to be permanently closed or if future cash flows from its operation were otherwise insufficient to recover its carrying value, we would record an impairment of the facility, which could be material, we could incur materially higher than expected operating costs and/or be required to make material additional capital expenditures (any or all of which may not be recoverable in rates), and natural gas reliability and electric generation could be jeopardized.

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Los Angeles County Franchise Agreement

In December 2024, the Los Angeles County Board of Supervisors granted SoCalGas a new, 20-year gas pipeline franchise. The franchise consists of an initial 10-year term beginning on January 9, 2025, followed by a 10-year term that Los Angeles County has the option to terminate. Prior to the granting of the new franchise, SoCalGas continued to serve customers in the unincorporated territory of Los Angeles County in accordance with its prior franchise.

Labor Relations

Field, technical and most clerical employees at SoCalGas are represented by the Utility Workers Union of America or the International Chemical Workers Union Council. The collective bargaining agreement for these employees covering wages, hours, working conditions, and medical and other benefit plans was due to expire on September 30, 2024, but was extended by mutual agreement through February 7, 2025, while SoCalGas and the unions continued negotiations. Two ratification votes in late 2024 were not successful. SoCalGas is currently operating under the terms of the expired agreement while the parties continue to negotiate revised terms and seek a positive ratification vote from union members. Until a new collective bargaining agreement is ratified by employees, there could be labor disruptions, though we do not anticipate that such labor disruptions would have a material impact on service.

Sempra Texas Utilities

Oncor relies on external financing as a significant source of liquidity for its capital requirements. In the event that Oncor fails to meet its capital requirements, access sufficient capital, or raise capital on favorable terms to finance its ongoing needs, we may elect to make additional capital contributions to Oncor (as our commitments to the PUCT prohibit us from making loans to Oncor), which could be substantial and reduce the cash available to us for other purposes, increase our indebtedness and ultimately materially adversely affect our results of operations, financial condition, cash flows and/or prospects. Oncor’s ability to make distributions may be limited by factors such as its credit ratings, regulatory capital requirements, increases in its capital plan, debt-to-equity ratio approved by the PUCT and other restrictions and considerations. In addition, Oncor will not make distributions if a majority of Oncor’s independent directors or any minority member director determines it is in the best interests of Oncor to retain such amounts to meet expected future requirements.

Rates and Cost Recovery

The PUCT issued a final order in Oncor’s most recent comprehensive base rate proceeding in April 2023, and rates implementing that order went into effect on May 1, 2023. In June 2023, the PUCT issued an order on rehearing in response to the motions for rehearing filed by Oncor and certain intervenor parties in the proceeding. The order on rehearing made certain technical and typographical corrections to the final order but otherwise affirmed the material provisions of the final order and did not require modification of the rates that went into effect on May 1, 2023. In September 2023, Oncor filed an appeal in Travis County District Court seeking judicial review of certain rate base disallowances and related expense effects of those disallowances in the PUCT’s order on rehearing. In February 2024, the court dismissed the appeal for lack of jurisdiction. In March 2024, Oncor appealed the court’s dismissal, which is currently with the Fifteenth Court of Appeals in Texas.

Off-Balance Sheet Arrangement

Our investment in Oncor Holdings is a variable interest in an unconsolidated entity. We discuss variable interests in Note 1 of the Notes to Consolidated Financial Statements.

Sempra Infrastructure

Sempra Infrastructure expects to fund capital expenditures, investments and operations in part with available funds, including existing credit facilities, and cash flows from operations from the Sempra Infrastructure businesses. We expect Sempra Infrastructure will require additional funding for the development and expansion of its portfolio of projects, which may be financed through a combination of funding from the parent and NCI owners, bank financing, issuances of debt, project financing, partnering in JVs and asset sales.

In 2024, 2023 and 2022, Sempra Infrastructure distributed $297 million, $730 million and $237 million, respectively, to its NCI owners, and NCI owners contributed $1,235 million, $1,770 million and $31 million, respectively, to Sempra Infrastructure.

Sempra Infrastructure is in various stages of development or construction of natural gas liquefaction projects, pipeline and terminal projects, and renewable power generation and sequestration projects, which we describe below. The successful development and/or construction of these projects is subject to numerous risks and uncertainties.

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With respect to projects in development, these risks and uncertainties include, as applicable depending on the project, any failure to:

▪secure binding customer commitments

▪identify suitable project and equity partners

▪obtain sufficient financing

▪reach agreement with project partners or other applicable parties to proceed

▪obtain, modify, and/or maintain permits and regulatory approvals, including LNG export applications to non-FTA countries

▪negotiate, complete and maintain suitable commercial agreements, which may include EPC, tolling, equity acquisition, governance, LNG sales, gas supply and transportation contracts

▪reach a positive final investment decision

With respect to projects under construction, these risks and uncertainties include, in addition to the risks described above as applicable to each project, construction delays and cost overruns.

An unfavorable outcome with respect to any of these factors could have a material adverse effect on (i) the development and construction of the applicable project, including a potential impairment of all or a substantial portion of the capital costs invested in the project to date, which could be material, and (ii) for any project that has reached a positive final investment decision, Sempra’s results of operations, financial condition, cash flows and/or prospects. For a further discussion of these risks, see “Part I – Item 1A. Risk Factors.”

The descriptions below discuss several HOAs, MOUs and other non-binding development agreements with respect to Sempra Infrastructure’s various development projects. These arrangements do not commit any party to enter into definitive agreements or otherwise participate in the applicable project, and the ultimate participation by the parties remains subject to negotiation and finalization of definitive agreements, among other factors.

LNG

Cameron LNG Phase 2 Project. Cameron LNG JV is developing a proposed expansion project that would add one electric drive liquefaction train with an expected maximum production capacity of approximately 6.75 Mtpa and would increase the production capacity of the existing three trains at the Cameron LNG Phase 1 facility by up to approximately 1 Mtpa through debottlenecking activities. The Cameron LNG JV site can accommodate additional trains beyond the proposed Cameron LNG Phase 2 project.

Cameron LNG JV has received major permits, which have been amended to allow the use of electric drives for a one-train electric drive expansion along with other design enhancements, and FTA and non-FTA approvals associated with the potential expansion. The non-FTA approval for the proposed Cameron LNG Phase 2 project includes, among other things, a May 2026 deadline to commence commercial exports, for which we expect to request an extension.

Sempra Infrastructure and the other Cameron LNG JV members, namely affiliates of TotalEnergies SE, Mitsui & Co., Ltd. and Japan LNG Investment, LLC, a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha, have entered into a non-binding HOA for the potential development of the Cameron LNG Phase 2 project. The non-binding HOA provides a commercial framework for the proposed project, including the contemplated allocation to SI Partners of 50.2% of the fourth train production capacity and 25% of the debottlenecking capacity from the project under tolling agreements. The non-binding HOA contemplates the remaining capacity to be allocated equally to the existing Cameron LNG Phase 1 facility customers.

Cameron LNG JV concluded additional value engineering work on the proposed project in December 2024, which improved the overall value of the project and enabled evaluation of another potential EPC contractor. In collaboration with our partners, we continue to evaluate these materials as well as the timeframe to make a final investment decision, which remains subject to satisfactory conclusion on the EPC process as well as negotiation and finalization of definitive offtake agreements and completion of all related financing and permitting activities.

Entergy Louisiana, LLC, a subsidiary of Entergy Corporation, and Cameron LNG JV have an electricity service agreement (and related ancillary agreements) for the supply to Cameron LNG JV of up to 950 MW of power from new renewable sources in Louisiana.

Expansion of the Cameron LNG Phase 1 facility beyond the first three trains is subject to certain restrictions and conditions under the JV project financing agreements, including among others, scope restrictions on expansion of the project unless appropriate prior consent is obtained from the existing project lenders. Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all the members, including with respect to the equity investment obligation of each member.

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ECA LNG Phase 1 Project. ECA LNG Phase 1 is constructing a one-train natural gas liquefaction facility at the site of Sempra Infrastructure’s existing ECA Regas Facility with a nameplate capacity of 3.25 Mtpa and an initial offtake capacity of 2.5 Mtpa. We do not expect the construction or operation of the ECA LNG Phase 1 project to disrupt operations at the ECA Regas Facility.

We received authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from the ECA LNG Phase 1 project. ECA LNG Phase 1 has definitive 20-year SPAs with an affiliate of TotalEnergies SE for approximately 1.7 Mtpa of LNG and with Mitsui & Co., Ltd. for approximately 0.8 Mtpa of LNG. The customers have a termination right if the ECA LNG Phase 1 project does not commence commercial operations under the SPAs by February 24, 2026, subject to certain additional conditions, for which we expect to request an extension if necessary.

We have an EPC contract with TP Oil & Gas Mexico, S. De R.L. De C.V., an affiliate of Technip Energies N.V., to construct the ECA LNG Phase 1 project. We estimate the total price of the EPC contract to be approximately $1.6 billion, with capital expenditures approximating $2.5 billion including capitalized interest at the project level and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates. We expect the ECA LNG Phase 1 project to commence commercial operations in the spring of 2026.

ECA LNG Phase 1 has a five-year loan agreement with a syndicate of seven external lenders that matures in December 2025, which we expect to extend, for an aggregate principal amount of up to $1.3 billion, of which $1.1 billion was outstanding at December 31, 2024. Proceeds from the loan are being used to finance the cost of construction of the ECA LNG Phase 1 project.

With respect to the ECA LNG Phase 1 and Phase 2 projects, recent and proposed changes to the Mexican Constitution and certain laws in Mexico and an unfavorable resolution of land disputes and permit challenges, in each case that we discuss in Note 15 of the Notes to Consolidated Financial Statements, could have a material adverse effect on the development and construction of these projects.

ECA LNG Phase 2 Project. Sempra Infrastructure is developing a second, large-scale natural gas liquefaction project at the site of its existing ECA Regas Facility. We expect the proposed ECA LNG Phase 2 project to be comprised of two trains and one LNG storage tank and produce approximately 12 Mtpa of export capacity. We expect that construction of the proposed ECA LNG Phase 2 project would conflict with the current operations at the ECA Regas Facility, which currently has firm storage service agreements and nitrogen injection service agreements with Shell and SEFE that expire in May 2028 and December 2025, respectively.

We received authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from the proposed ECA LNG Phase 2 project.

We have non-binding MOUs and/or HOAs with Mitsui & Co., Ltd., an affiliate of TotalEnergies SE, and ConocoPhillips that provide a framework for their potential offtake of LNG from the proposed ECA LNG Phase 2 project and potential acquisition of an equity interest in ECA LNG Phase 2.

PA LNG Phase 1 Project. Sempra Infrastructure is constructing a natural gas liquefaction project on a greenfield site that it owns in the vicinity of Port Arthur, Texas, located along the Sabine-Neches waterway. The PA LNG Phase 1 project will consist of two liquefaction trains, two LNG storage tanks, a marine berth and associated loading facilities and related infrastructure necessary to provide liquefaction services with a nameplate capacity of approximately 13 Mtpa and an initial offtake capacity of approximately 10.5 Mtpa.

Sempra Infrastructure has received authorizations from the DOE that permit the LNG to be produced from the PA LNG Phase 1 project to be exported to all current and future FTA and non-FTA countries. In April 2019, the FERC approved the siting, construction and operation of the PA LNG Phase 1 project. Port Arthur LNG has received authorization from the FERC to increase its work force and implement a 24-hours-per-day construction schedule to further enhance construction efficiency while reducing temporal impacts to the community and environment in the vicinity of the project. The authorization provides the EPC contractor with more optionality to meet or exceed the project’s construction schedule.

The PA LNG Phase 1 project holds two Clean Air Act Prevention of Significant Deterioration permits issued by the TCEQ, which we refer to as the “2016 Permit” and the “2022 Permit.” The 2022 Permit also governs emissions for the proposed PA LNG Phase 2 project. In November 2023, a panel of the U.S. Court of Appeals for the Fifth Circuit issued a decision to vacate and remand the 2022 Permit to the TCEQ for additional explanation of the agency’s permit decision. In February 2024, the court withdrew its opinion and referred the case to the Supreme Court of Texas to resolve the question of the appropriate standard to be applied by the TCEQ. In February 2025, the Supreme Court of Texas adopted Port Arthur LNG’s interpretation of the standard. Port Arthur LNG continues to litigate this matter before the U.S. Court of Appeals for the Fifth Circuit, which will apply the standard adopted by the Supreme Court of Texas. The 2022 Permit is effective during the pending litigation. The 2016 Permit was not the subject of, and is unaffected by, the pending litigation of the 2022 Permit. Construction of the PA LNG Phase 1 project is proceeding

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uninterrupted under existing permits, and we do not currently anticipate the pending litigation to materially impact the PA LNG Phase 1 project cost, schedule or expected commercial operations at this stage.

Sempra Infrastructure has definitive SPAs for LNG offtake from the PA LNG Phase 1 project with:

▪an affiliate of ConocoPhillips for a 20-year term for 5 Mtpa of LNG, as well as a natural gas supply management agreement whereby an affiliate of ConocoPhillips will manage the feed gas supply requirements for the PA LNG Phase 1 project.

▪RWE Supply & Trading GmbH, a subsidiary of RWE AG, for a 15-year term for 2.25 Mtpa of LNG.

▪INEOS for a 20-year term for approximately 1.4 Mtpa of LNG.

▪ORLEN for a 20-year term for approximately 1 Mtpa of LNG.

▪ENGIE S.A. for a 15-year term for approximately 0.875 Mtpa of LNG.

We have an EPC contract with Bechtel to construct the PA LNG Phase 1 project, which has an estimated price of approximately $10.7 billion. We estimate the capital expenditures for the PA LNG Phase 1 project will be approximately $13 billion including capitalized interest at the project level and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates. We expect the first and second trains of the PA LNG Phase 1 project to commence commercial operations in 2027 and 2028, respectively.

As we discuss in Note 12 of the Notes to the Consolidated Financial Statements, SI Partners and ConocoPhillips have provided guarantees relating to their respective affiliate’s commitment to make its pro rata equity share of capital contributions to fund 110% of the development budget of the PA LNG Phase 1 project, in an aggregate amount of up to $9.0 billion. SI Partners’ guarantee covers 70% of this amount plus enforcement costs of its guarantee. As of December 31, 2024, an aggregate amount of $2.7 billion has been paid by SI Partners’ subsidiary in satisfaction of its commitment to fund its portion of the development budget of the PA LNG Phase 1 project.

Port Arthur LNG has a seven-year term loan facility for an aggregate principal amount of approximately $6.8 billion and an initial working capital facility for up to $200 million, each of which matures in March 2030. At December 31, 2024, $1.1 billion of borrowings were outstanding under the term loan facility agreement. Proceeds from the loan are being used to finance the cost of construction of the PA LNG Phase 1 project.

In November 2024, Port Arthur LNG signed an agreement to issue senior secured notes in January 2025 for $750 million and April 2025 for $250 million. The net proceeds from the January 2025 issuance and the expected net proceeds from the April 2025 issuance were or will be used to pay transaction fees and repay borrowings under the existing Port Arthur LNG term loan facility. The senior secured notes mature in December 2042 and the January 2025 and April 2025 issuances bear interest at the rate of 6.27% and 6.32% per annum, respectively.

PA LNG Phase 2 Project. Sempra Infrastructure is developing a second phase of the Port Arthur natural gas liquefaction project that we expect will be a similar size to the PA LNG Phase 1 project. We are progressing the development of the proposed PA LNG Phase 2 project, while continuing to evaluate overall opportunities to develop the entirety of the Port Arthur site.

In September 2023, the FERC approved the siting, construction and operation of the proposed PA LNG Phase 2 project, including the potential addition of up to two liquefaction trains. In February 2020, Sempra Infrastructure filed an application with the DOE to permit LNG produced from the proposed PA LNG Phase 2 project to be exported to all current and future non-FTA countries. We received FTA authorization from the DOE in July 2020.

As we discuss above, a U.S. federal court previously issued and subsequently withdrew a decision that would have vacated and remanded the 2022 Permit authorizing emissions from the PA LNG Phase 1 and Phase 2 projects to the TCEQ for additional explanation of the agency’s permit decision. The U.S. Court of Appeals for the Fifth Circuit referred the case to the Supreme Court of Texas to resolve the question of the appropriate standard to be applied by the TCEQ. In February 2025, the Supreme Court of Texas adopted Port Arthur LNG’s interpretation of the standard. Port Arthur LNG continues to litigate this matter before the U.S. Court of Appeals for the Fifth Circuit, which will apply the standard adopted by the Supreme Court of Texas. The 2022 Permit is effective during the pending litigation.

Sempra Infrastructure has entered into a non-binding HOA for a 20-year SPA with Aramco for 5 Mtpa of LNG offtake from the proposed PA LNG Phase 2 project. The HOA further contemplates Aramco’s 25% participation in the project-level equity of the PA LNG Phase 2 project.

In July 2024, Sempra Infrastructure entered into an $8.2 billion EPC contract with Bechtel for the proposed PA LNG Phase 2 project. The EPC contract contemplates the construction of two liquefaction trains capable of producing approximately 13 Mtpa, an additional LNG storage tank and marine berth and associated loading facilities and related infrastructure necessary to provide liquefaction services. We have no obligation to move forward on the EPC contract, and we may release Bechtel to perform

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portions of the work pursuant to limited notices to proceed. The price is subject to increase if certain limited notices to proceed and the full notice to proceed are not issued, each by specified dates. We expect to work with Bechtel with respect to such changes based on the ultimate timeline for the project and plan to fully release Bechtel to perform all the work to construct the PA LNG Phase 2 project only after we reach a final investment decision, which we are targeting in 2025, and after certain other conditions are met, including obtaining permits, executing definitive agreements for LNG offtake and equity investments, and securing project financing.

Vista Pacifico LNG Liquefaction Project. Sempra Infrastructure is developing the Vista Pacifico LNG project, a mid-scale natural gas liquefaction export facility proposed to be located in the vicinity of the Port of Topolobampo in Sinaloa, Mexico. In June 2024, we extended the non-binding development agreement with the CFE through December 2025. We continue to progress with the CFE on the negotiation of definitive agreements, including a natural gas supply agreement. The proposed LNG export terminal would be supplied with U.S. natural gas and would use excess capacity on existing pipelines in Mexico with the intent of helping to meet growing demand for natural gas and LNG in the Mexican and Pacific markets.

Sempra Infrastructure received authorization from the DOE to permit the export of U.S.-produced natural gas to Mexico and for LNG produced from the proposed Vista Pacifico LNG facility to be re-exported to all current and future FTA countries and non-FTA countries.

In March 2022, TotalEnergies SE and Sempra Infrastructure entered into a non-binding MOU that contemplates TotalEnergies SE potentially contracting approximately one-third of the long-term export production of the proposed Vista Pacifico LNG project and potentially participating as a minority partner in the project.

Asset and Supply Optimization. As we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” Sempra Infrastructure enters into hedging transactions to help mitigate commodity price risk and optimize the value of its LNG, natural gas pipelines and storage, and power-generating assets. Some of these derivatives that we use as economic hedges do not meet the requirements for hedge accounting, or hedge accounting is not elected, and as a result, the changes in fair value of these derivatives are recorded in earnings. Consequently, significant changes in commodity prices have in the past and could in the future result in earnings volatility, which may be material, as the economic offset of these derivatives may not be recorded at fair value.

Off-Balance Sheet Arrangements. Our investment in Cameron LNG JV is a variable interest in an unconsolidated entity. We discuss variable interests in Note 1 of the Notes to Consolidated Financial Statements.

In June 2021, Sempra provided a promissory note, which constitutes a guarantee, for the benefit of Cameron LNG JV with a maximum exposure to loss of $165 million. The guarantee will terminate upon full repayment of Cameron LNG JV’s debt, scheduled to occur in 2039, or replenishment of the amount withdrawn by Sempra Infrastructure from the SDSRA. We discuss this guarantee in Note 5 of the Notes to Consolidated Financial Statements.

In July 2020, Sempra entered into a Support Agreement, which contains a guarantee and represents a variable interest, for the benefit of CFIN with a maximum exposure to loss of $979 million. The guarantee will terminate upon full repayment of the guaranteed debt by 2039, including repayment following an event in which the guaranteed debt is put to Sempra. We discuss this guarantee in Notes 1, 5 and 10 of the Notes to Consolidated Financial Statements.

Energy Networks

Sonora Pipeline. Sempra Infrastructure’s Sonora natural gas pipeline consists of two pipeline segments, the Sasabe-Puerto Libertad-Guaymas segment and the Guaymas-El Oro segment. Each segment has its own service agreement with the CFE. Following the start of commercial operations of the Guaymas-El Oro segment, Sempra Infrastructure reported damage to the pipeline in the Yaqui territory that has made that section inoperable since August 2017 because it was not able to be repaired due to legal challenges, which were resolved in March 2023, by some members of the Yaqui tribe.

In September 2019, Sempra Infrastructure and the CFE reached an agreement to modify the tariff structure and extend the term of the contract by 10 years. Under the revised agreement, the CFE will resume making payments only when the damaged section of the Guaymas-El Oro segment of the Sonora pipeline is back in service.

Sempra Infrastructure and the CFE have agreed to an amendment to their transportation services agreement and to re-route the portion of the pipeline that is in the Yaqui territory, whereby the CFE would pay for the re-routing with a new tariff. This amendment will terminate if certain conditions are not met, and Sempra Infrastructure retains the right to terminate the transportation services agreement and seek to recover its reasonable and documented costs and lost profit. Sempra Infrastructure continues to acquire and pursue the necessary rights-of-way and permits for the portion of the pipeline that needs to be re-routed.

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The Guaymas-El Oro segment of the Sonora pipeline currently constitutes a Sole Risk Project under the terms of the SI Partners limited partnership agreement, which means that Sempra Infrastructure holds a 100% interest in the project. Sole Risk Projects are separated from other SI Partners projects and are conducted at Sempra’s sole cost, expense and liability and Sempra Infrastructure receives, through the acquisition of Sole Risk Interests, any economic and other benefits from such projects. At December 31, 2024, Sempra Infrastructure had $401 million in PP&E, net, related to the Guaymas-El Oro segment of the Sonora pipeline, which could be subject to impairment if Sempra Infrastructure is unable to re-route a portion of the pipeline and resume operations or if Sempra Infrastructure terminates the contract and is unable to obtain recovery, which in each case could have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.

Refined Products Terminals. Sempra Infrastructure owns and operates terminals for the receipt, storage, and delivery of refined products; one such terminal located in Topolobampo commenced commercial operations in June 2024. Sempra Infrastructure is also developing terminals for the receipt, storage, and delivery of refined products in the vicinity of Manzanillo and Ensenada.

Port Arthur Pipeline Louisiana Connector. Sempra Infrastructure is constructing the Port Arthur Pipeline Louisiana Connector, a 72-mile pipeline connecting the PA LNG Phase 1 project to Gillis, Louisiana. In April 2019, the FERC approved the siting, construction and operation of the Port Arthur Pipeline Louisiana Connector, which will be used to supply feed gas to the PA LNG Phase 1 project. Sempra Infrastructure received FERC approval to implement construction process enhancements and minor modifications to several discrete sections of the Port Arthur Pipeline Louisiana Connector. These modifications are intended to decrease environmental impacts, accommodate landowner routing requests and enhance construction procedures. We expect the Port Arthur Pipeline Louisiana Connector to be ready for service ahead of the PA LNG Phase 1 project’s gas requirements. We estimate the capital expenditures for the project will be approximately $1 billion, including capitalized interest at the project level and project contingency. The actual amount of these capital expenditures may differ substantially from our estimates.

Louisiana Storage. Sempra Infrastructure is constructing Louisiana Storage, a 12.5-Bcf salt dome natural gas storage facility to support the PA LNG Phase 1 project. The construction includes an 11-mile pipeline that will connect to the Port Arthur Pipeline Louisiana Connector. In September 2022, the FERC approved the development of the project. We expect Louisiana Storage to be ready for service in time to support the needs of the PA LNG Phase 1 project. We estimate the capital expenditures for the project will be approximately $300 million, including capitalized interest at the project level and project contingency. The actual amount of these capital expenditures may differ substantially from our estimates.

Low Carbon Solutions

Cimarrón Wind. Sempra Infrastructure has made a positive final investment decision on and begun constructing the Cimarrón Wind project, an approximately 320 MW wind generation facility in Baja California, Mexico. Sempra Infrastructure has a 20-year PPA with Silicon Valley Power for the long-term supply of renewable energy to the City of Santa Clara, California. Cimarrón Wind will utilize Sempra Infrastructure’s existing cross-border high voltage transmission line to interconnect and deliver clean energy to the East County substation in San Diego County. We estimate the capital expenditures for the project will be approximately $550 million, including capitalized interest at the project level and project contingency. The actual amount of these capital expenditures may differ substantially from our estimates. We expect the Cimarrón Wind project to begin generating energy in late 2025 and commence commercial operations in the first half of 2026.

Hackberry Carbon Sequestration Project. Sempra Infrastructure is developing the potential Hackberry Carbon Sequestration project near Hackberry, Louisiana, together with TotalEnergies SE, Mitsui & Co., Ltd. and Mitsubishi Corporation. This proposed project is designed to permanently sequester carbon dioxide from the Cameron LNG Phase 1 facility, the proposed Cameron LNG Phase 2 project and potentially other sources. In 2021, Sempra Infrastructure filed an application with the EPA for a Class VI carbon injection well permit, which is under review by the State of Louisiana.

Legal and Regulatory Matters

See Note 15 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors” for discussions of the following legal and regulatory matters affecting our operations in Mexico and risks associated with Mexican laws, policies and government influence:

Energía Costa Azul

▪Land Disputes

▪Environmental and Social Impact Permits

One or more unfavorable final decisions on these land disputes or environmental and social impact permit challenges could materially adversely affect our existing natural gas regasification operations and proposed natural gas liquefaction projects at the

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site of the ECA Regas Facility and have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.

Regulatory and Other Actions by the Mexican Government

▪Amendments to Mexico’s Hydrocarbons Law

▪Amendments to Mexico’s Electricity Industry Law

Sempra Infrastructure and other parties affected by these amendments to Mexican law have challenged them by filing amparo and other claims, some of which remain pending. In particular, Sempra Infrastructure filed one lawsuit concerning the provision of Mexico’s Electricity Industry Law permitting revocation of self-supply permits deemed improperly obtained that was dismissed by the court. Consequently, the CRE may be required to seek to revoke such self-supply permits, under a legal standard that is ambiguous and not well defined under the law. An unfavorable decision on one or more of these amparo or other challenges, the impact of the amendments that have become effective (due to unsuccessful amparo challenges or otherwise), or the possibility of future reforms to the energy industry through additional amendments to Mexican laws, regulations or rules (including through amendments to the Mexican Constitution) may impact our ability to operate our facilities at existing levels or at all, may result in increased costs for Sempra Infrastructure and its customers, may adversely affect our ability to develop new projects, may result in decreased revenues and cash flows, and may negatively impact our ability to recover the carrying values of our investments in Mexico, any of which may have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.

Subsequent to the federal elections in Mexico in 2024 and, as noted above, the Mexican government has begun to introduce significant changes to the Mexican Constitution, which will require changes in laws, policies, and regulations in order to be implemented. These changes have included Mexican Constitutional reforms affecting the judiciary and the for-profit status of certain state-owned enterprises. The changes to the judiciary include a requirement that all judges be elected rather than appointed. The energy reforms have the potential to increase government control and participation in the energy sector and to create novel challenges for infrastructure development and operations. Additionally, a set of six energy-related laws, including modifications to the Hydrocarbons Law and Electricity Industry Law, were submitted to Mexico’s Congress in January 2025. The legislative session runs from February 1 to April 30, and the government is targeting approval by the end of March 2025. These reforms and any further Mexican Constitutional, legal or regulatory changes could affect the Mexican economy, energy sector and our businesses, the extent of which we currently are unable to predict.

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SOURCES AND USES OF CASH

We discuss herein our sources and uses of cash for the year ended December 31, 2024 compared to the year ended December 31, 2023. For a discussion of our sources and uses of cash for the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to “Part II – Item 7. MD&A – Sources and Uses of Cash” in our 2023 annual report on Form 10-K filed with the SEC on February 27, 2024.

The following tables include only significant changes in cash flow activities for each of the Registrants.

CASH FLOWS FROM OPERATING ACTIVITIES
(Dollars in millions)
Years ended December 31,	Sempra			SDG&E		SoCalGas
2024		$	4,907	$	2,073	$	1,791
2023		6,218		1,936		1,389
Change		$	(1,311)	$	137	$	402
Change in net margin posted, current and noncurrent		$	(1,142)
Change in fixed-price contracts and other derivatives, current and noncurrent		(432)		$	(127)	$	(305)
Change in qualified pension liability		(211)		(83)		(130)
Change in income taxes receivable/payable, net		(191)		445
Change in GHG allowances, current and noncurrent		(73)		40		(155)
Change in accounts receivable(1)		(50)		305		(220)
(Lower) higher net income, adjusted for noncash items included in earnings		(45)		78		40
Change in legal reserve, current and noncurrent		82				82
Lower net decrease in Reserve for Aliso Canyon costs, current and noncurrent, due to $94 lower payments offset by $6 lower accruals		88				88
Change in GHG obligations, current and noncurrent		99		39		55
Change in accounts payable(2)		139		(63)		76
Higher distributions from Oncor Holdings		162
Change in regulatory accounts, current and noncurrent		249		(456)		704
Change in customer deposits				(47)
Change in inventories, current and noncurrent(3)						117
Other		14		6		50
		$	(1,311)	$	137	$	402

(1)    Change primarily due to a decrease in natural gas consumption and lower gas rates at SoCalGas offset by timing of customer payments.

(2)    Change primarily due to a decrease in payments to suppliers at Sempra Infrastructure and a decrease in payments for gas purchases at SoCalGas, offset by an increase in payments to CCAs at SDG&E.

(3)    Change primarily due to a decrease in purchases of materials and supplies and a decrease in natural gas inventory.

CASH FLOWS FROM INVESTING ACTIVITIES
(Dollars in millions)
Years ended December 31,	Sempra			SDG&E		SoCalGas
2024		$	(9,118)	$	(2,461)	$	(2,231)
2023		(8,716)		(2,472)		(2,020)
Change		$	(402)	$	11	$	(211)
Higher contributions to Oncor Holdings		$	(609)
Decrease (increase) in capital expenditures		182		$	18	$	(211)
Other		25		(7)
		$	(402)	$	11	$	(211)

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CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
Years ended December 31,	Sempra			SDG&E		SoCalGas
2024		$	5,424	$	338	$	450
2023		2,419		579		612
Change		$	3,005	$	(241)	$	(162)
Lower payments on short-term debt with maturities greater than 90 days		$	2,923			$	800
Higher (lower) issuances of long-term debt		2,124		$	(795)	97
Higher issuances of common stock		1,074
Lower distributions to NCI		433
Termination of interest rate and settlement of cross-currency swaps		145
Higher advances from unconsolidated affiliates		54
Lower contributions from NCI		(335)
Change in borrowings and repayments of short-term debt, net		(1,109)		622		(1,455)
(Lower) higher issuances of short-term debt with maturities greater than 90 days		(1,119)				700
Net proceeds from sales of NCI in 2023		(1,219)
Lower (higher) payments on long-term debt and finance leases				48		(204)
Higher common dividends paid				(125)		(100)
Other		34		9
		$	3,005	$	(241)	$	(162)

Capital Expenditures for PP&E

We invest the majority of our capital expenditures in Sempra California, primarily for transmission and distribution improvements, including pipeline and wildfire safety. The following table summarizes, by segment, capital expenditures for PP&E for the last three years.

CAPITAL EXPENDITURES FOR PP&E
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra:
Sempra California(1)	$	4,753	$	4,560	$	4,466
Sempra Infrastructure	3,459		3,832		884
Segment totals	8,212		8,392		5,350
Parent and other	3		5		7
Total Sempra	$	8,215	$	8,397	$	5,357

(1)    Includes capital expenditures for PP&E of $2,522, $2,540, and $2,473 at SDG&E and $2,231, $2,020, and $1,993 at SoCalGas for 2024, 2023, and 2022, respectively.

Capital Expenditures for Investments

The following table summarizes, by segment, capital expenditures for investments in entities that we account for under the equity method for the last three years.

CAPITAL EXPENDITURES FOR INVESTMENTS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra:
Sempra Texas Utilities	$	976	$	367	$	346
Sempra Infrastructure	12		15		30
Total Sempra	$	988	$	382	$	376

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Future Capital Expenditures for PP&E and Investments

The amounts and timing of capital expenditures for PP&E and certain investments are generally subject to approvals by various regulatory and other governmental and environmental bodies, including the CPUC, the FERC and the PUCT, and various other factors described in this MD&A and in “Part I – Item 1A. Risk Factors.” In 2025, we expect to make capital expenditures for PP&E and investments of approximately $12.5 billion, as summarized by segment in the following table.

FUTURE CAPITAL EXPENDITURES FOR PP&E AND INVESTMENTS
(Dollars in millions)
	Year ending December 31, 2025
Sempra:
Sempra California(1)	$	4,740
Sempra Texas Utilities	1,935
Sempra Infrastructure	5,777
Segment totals	12,452
Parent and other	2
Total Sempra	$	12,454

(1)    Includes expected future capital expenditures of $2,632 and $2,108 at SDG&E and SoCalGas, respectively.

We expect the majority of our capital expenditures for PP&E and investments in 2025 will relate to investments in transmission and distribution safety and reliability at our regulated public utilities and construction of the PA LNG Phase 1 project, ECA LNG Phase 1 project and natural gas pipelines at Sempra Infrastructure.

From 2025 through 2029, and subject to the factors described below, which could cause these estimates to vary substantially, Sempra expects to make aggregate capital expenditures for PP&E and investments of approximately $41.4 billion, as follows: $22.4 billion at Sempra California (which includes $12.7 billion at SDG&E and $9.7 billion at SoCalGas), $8.1 billion at Sempra Texas Utilities, and $10.9 billion at Sempra Infrastructure. Capital expenditure amounts for PP&E include capitalized interest and AFUDC related to debt.

When (i) including Sempra’s proportionate ownership interest in expected capital expenditures for PP&E at unconsolidated equity method investees while excluding Sempra’s expected capital contributions to those unconsolidated equity method investees and (ii) excluding NCI’s proportionate ownership interest in expected capital expenditures for PP&E at Sempra and at unconsolidated equity method investees, we expect capital expenditures for PP&E from 2025 through 2029 to total $55.5 billion.

Oncor currently anticipates that its five-year capital expenditures plan could grow by approximately $12 billion over the 2025 through 2029 period due to potential additions to its system resiliency plan expected to occur in 2028 and 2029, potential projects that are pending regulatory action and customer projects that are in Oncor’s transmission interconnection queue but do not yet have signed agreements. Significant changes in Oncor’s capital expenditures plan could result in significant changes to our capital expenditures plan. To the extent Oncor’s five-year capital expenditures plan grows, Sempra expects that its five-year plan for capital expenditures for PP&E and investments, as well as its plan when including its proportionate ownership interest in Oncor’s capital expenditures and excluding Sempra’s expected capital contributions to Oncor, would each grow by Sempra’s 80.25% interest in Oncor’s incremental capital expenditures.

Periodically, we review our construction, investment and financing programs and revise them in response to changes in regulation, economic conditions, competition, customer growth, inflation, customer rates, the cost and availability of capital, and safety and environmental requirements.

Our level of capital expenditures for PP&E and investments in the next few years may vary substantially and will depend on, among other things, the cost and availability of financing, regulatory approvals, changes in tax law and business opportunities providing desirable rates of return, among various other factors described in this MD&A and in “Part I – Item 1A. Risk Factors.” We aim to finance our capital expenditures for PP&E and investments in a manner that will maintain our investment-grade credit ratings and capital structure, but there is no guarantee that we will be able to do so.

Rate Base

For SDG&E and SoCalGas, rate base is the value of assets on which SDG&E and SoCalGas are permitted to earn a specified rate of return in accordance with rules set by regulatory agencies, including the CPUC and the FERC (for SDG&E), which is calculated using a 13-month average in accordance with CPUC methodology as adopted in rate-setting proceedings. The following table summarizes the weighted-average rate base for SDG&E and SoCalGas for the last three years.

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WEIGHTED-AVERAGE RATE BASE
(Dollars in millions)
	2024		2023		2022
SDG&E	$	16,842	$	15,220	$	13,780
SoCalGas	12,446		11,671		10,494

The increase in weighted-average rate base reflects the significant capital investments that SDG&E and SoCalGas have made in transmission and distribution safety and reliability. We expect the weighted-average rate base to continue to increase in 2025 based on our expected capital investments.

For Oncor, rate base represents the total invested capital, as adjusted in accordance with PUCT rules, at the end of the previous calendar year as reported in the Earnings Monitoring Report filed with the PUCT on an annual basis. Oncor’s regulatory rate base as reported in these filings as of December 31, 2023 and 2022 was $23.1 billion and $20.7 billion, respectively. As calculated on a similar basis, its estimated regulatory rate base at December 31, 2024 was $26.6 billion. The increase in rate base reflects the significant capital investments that Oncor has made in its transmission and distribution system, and we expect rate base to continue to increase in 2025 based on Oncor’s expected capital investments.

Capital Stock Transactions

Sempra

Cash provided by issuances of common stock was:

▪$1,219 million in 2024 

▪$145 million in 2023

▪$4 million in 2022

Cash used for repurchases of common stock was:

▪$43 million in 2024 

▪$32 million in 2023

▪$478 million in 2022

We discuss the issuances and repurchases of common stock in Note 12 of the Notes to Consolidated Financial Statements.

Dividends

Sempra

Sempra paid cash dividends of:

▪$1,499 million for common stock and $44 million for preferred stock in 2024

▪$1,483 million for common stock and $44 million for preferred stock in 2023

▪$1,430 million for common stock and $44 million for preferred stock in 2022

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DIVIDENDS PER SHARE ON SEMPRA COMMON STOCK

(As approved by our board of directors)

On February 24, 2025, our board of directors declared a dividend of $0.645 per share on our common stock and a dividend of $24.375 per share on our series C preferred stock, both payable on April 15, 2025.

All declarations of dividends on our common stock and preferred stock are made at the discretion of the board of directors. While we view dividends as an integral component of shareholder return, the amount of future dividends will depend on earnings, cash flows, financial and legal requirements, and other relevant factors at that time. As a result, Sempra’s dividends on common stock and preferred stock declared on a historical basis may not be indicative of future declarations.

SDG&E

In 2024, 2023 and 2022, SDG&E paid common stock dividends to Enova Corporation and Enova Corporation paid corresponding dividends to Sempra of $225 million, $100 million and $100 million, respectively. SDG&E’s dividends on common stock declared on an annual historical basis may not be indicative of future declarations. Rather, SDG&E’s common stock dividends in the next few years may be impacted as available cash is used to maintain its authorized capital structure while supporting its capital investment program.

Enova Corporation, a wholly owned subsidiary of Sempra, owns all of SDG&E’s outstanding common stock. Accordingly, dividends paid by SDG&E to Enova Corporation and dividends paid by Enova Corporation to Sempra are eliminated in Sempra’s consolidated financial statements.

SoCalGas

In 2024 and 2023, SoCalGas paid common stock dividends to Pacific Enterprises and Pacific Enterprises paid corresponding dividends to Sempra of $200 million and $100 million, respectively. SoCalGas did not declare or pay common stock dividends in 2022. SoCalGas’ dividends on common stock declared on an annual historical basis may not be indicative of future declarations. Rather, SoCalGas’ common stock dividends in the next few years may be impacted as available cash is used to maintain its authorized capital structure while supporting its capital investment program.

Pacific Enterprises, a wholly owned subsidiary of Sempra, owns all of SoCalGas’ outstanding common stock. Accordingly, dividends paid by SoCalGas to Pacific Enterprises and dividends paid by Pacific Enterprises to Sempra are eliminated in Sempra’s consolidated financial statements.

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Dividend Restrictions

The board of directors for each of Sempra, SDG&E and SoCalGas has the discretion to determine whether to declare and, if declared, the amount of any dividends by each such entity. The CPUC’s regulation of SDG&E’s and SoCalGas’ capital structures limits the amounts that are available for loans and dividends to Sempra. At December 31, 2024, based on these regulations, Sempra could have received combined loans and dividends of approximately $672 million from SDG&E and $457 million from SoCalGas. In addition, the terms of Sempra’s series C preferred stock limit Sempra’s ability to declare dividends on its common stock under certain circumstances.

We provide additional information about dividend restrictions in “Restricted Net Assets” in Note 1 of the Notes to Consolidated Financial Statements and in Note 11 of the Notes to Consolidated Financial Statements.

Capitalization

Our total capitalization, which is the sum of total debt and equity, and our debt-to-capitalization ratio, which is calculated as total debt as a percentage of total capitalization, was as follows:

TOTAL CAPITALIZATION AND DEBT-TO-CAPITALIZATION RATIO
(Dollars in millions)
	Total capitalization				Debt-to-capitalization ratio
	December 31,
	2024		2023		2024		2023
Sempra	$	73,636	$	64,730	49	%	48	%
SDG&E	21,041		19,796		50		50
SoCalGas	16,602		15,167		51		51

In 2024 compared to 2023, Sempra’s total capitalization increased by $8.9 billion (14%) due to:

▪increase in long-term debt

▪increase in equity primarily from comprehensive income exceeding dividends, issuances of common stock and contributions from NCI

Offset by:

▪decrease in short-term debt

▪distributions to NCI

In 2024 compared to 2023, SDG&E’s and SoCalGas’ total capitalization increased by $1.2 billion (6%) and $1.4 billion (9%), respectively, due to increases in equity from comprehensive income exceeding dividends and increases in debt.

CRITICAL ACCOUNTING ESTIMATES

Management views the accounting estimates that we describe below as critical because their application is the most relevant, judgmental and/or material to our financial position and results of operations, and/or because they require the use of material judgments and estimates. We discuss critical accounting estimates that are material to our financial statements with the Audit Committee of Sempra’s board of directors.

REGULATORY ACCOUNTING

Sempra, SDG&E, SoCalGas

As regulated entities, SDG&E’s and SoCalGas’ customer rates, as set and monitored by regulators, are designed to recover the cost of providing service and to provide the opportunity to realize their authorized rates of return on their investments. SDG&E and SoCalGas assess probabilities of future rate recovery associated with regulatory account balances at the end of each reporting period and whenever new and/or unusual events occur, such as:

▪changes in the regulatory and political environment or the utility’s competitive position

▪issuance of a regulatory commission order

▪passage of new legislation

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To the extent that circumstances associated with regulatory balances change, the regulatory balances are evaluated and adjusted if appropriate.

Significant management judgment is required to evaluate the anticipated recovery of regulatory assets and revenues subject to refund, as well as the existence and amount of regulatory liabilities. Adverse regulatory or legislative actions could materially impact the amounts of our regulatory assets and liabilities and could materially adversely impact our results of operations and financial condition. Specifically, if future recovery of costs ceases to be probable, all or part of the associated regulatory assets would need to be written off against current period earnings, or adverse regulatory or legislative actions could give rise to material new or higher regulatory liabilities. We discuss details of SDG&E’s and SoCalGas’ regulatory assets and liabilities and additional factors that management considers when assessing probabilities associated with regulatory balances in Notes 1, 4, 14 and 15 of the Notes to Consolidated Financial Statements.

INCOME TAXES

Sempra, SDG&E, SoCalGas

Our income tax expense and related balance sheet amounts involve significant management judgments and estimates. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. When we evaluate the anticipated resolution of income tax issues, we consider:

▪ past resolutions of the same issue or similar issues

▪ the status of any income tax examination in progress

▪ positions taken by taxing authorities with other taxpayers with similar issues

The likelihood of deferred income tax recovery is based on analyses of the deferred income tax assets and our expectation of future taxable income, based on our strategic planning. Should a change in facts or circumstances lead to a change in judgment about the ultimate realizability of a deferred tax asset, we would record or adjust the related valuation allowance in the period that the change in facts and circumstances occurs, along with a corresponding increase or decrease in the provision for income taxes.

Actual income taxes could vary from estimated amounts because of:

▪ future impacts of various items, including changes in tax laws, regulations, interpretations and rulings

▪ our financial condition in future periods

▪ the resolution of various income tax issues between us and taxing and regulatory authorities

Unrecognized income tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our results of operations, financial condition and cash flows.

We discuss these matters and additional information related to accounting for income taxes, including uncertainty in income taxes, in Note 7 of the Notes to Consolidated Financial Statements.

PENSION AND PBOP PLANS

Sempra, SDG&E, SoCalGas

To measure our pension and PBOP obligations, costs and liabilities, we rely on several assumptions. We consider current market conditions, including interest rates, in making these assumptions. We review these assumptions annually and update when appropriate. 

The critical assumptions used to develop the required estimates include the following key factors: 

▪discount rates

▪expected return on plan assets

▪health care cost trend rates

▪interest crediting rate on cash balance accounts

▪mortality rate

▪rate of compensation increases

▪termination and retirement rates

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▪utilization of postretirement welfare benefits

▪payout elections (lump sum or annuity)

▪lump sum interest rates

The actuarial assumptions we use may differ materially from actual results due to: 

▪return on plan assets

▪changing market and economic conditions

▪higher or lower withdrawal rates

▪longer or shorter participant life spans

▪more or fewer lump sum versus annuity payout elections made by plan participants

▪higher or lower retirement rates

Changes in the estimated costs or timing of pension and PBOP, or the assumptions and judgments used by management underlying these estimates (primarily the discount rate and expected return on plan assets), as well as changes in the circumstances associated with rate recovery, could have a material effect on the recorded expenses and liabilities. The following tables summarize the impact to our projected benefit obligation for pension and accumulated benefit obligation for PBOP at December 31, 2024, and 2024 net periodic benefit costs, in each case if the discount rate or expected return on plan assets were changed by 1%.

IMPACT DUE TO INCREASE/DECREASE IN DISCOUNT RATE
(Dollars in millions)
	Sempra				SDG&E				SoCalGas
	Increase		Decrease		Increase		Decrease		Increase		Decrease
Pension:
(Decrease) increase to projected benefit obligation, net	$	(292)	$	(379)	$	(38)	$	59	$	(241)	$	304
(Decrease) increase to net periodic benefit cost	(1)		16		2		(1)		(4)		17
PBOP:
(Decrease) increase to accumulated benefit obligation, net	(67)		94		(9)		22		(56)		69
(Decrease) increase to net periodic benefit cost	(6)		7		(1)		1		(4)		5

IMPACT DUE TO INCREASE/DECREASE IN RETURN ON PLAN ASSETS
(Dollars in millions)
	Sempra				SDG&E				SoCalGas
	Increase		Decrease		Increase		Decrease		Increase		Decrease
Pension:
(Decrease) increase to net periodic benefit cost	$	(39)	$	39	$	(9)	$	9	$	(28)	$	28
PBOP:
(Decrease) increase to net periodic benefit cost	(12)		12		(1)		1		(10)		10

For SDG&E and SoCalGas plans, the effects of the assumptions on earnings are expected to be recovered in rates and therefore are offset in regulatory accounts. We provide details of our pension and PBOP plans in Note 8 of the Notes to Consolidated Financial Statements.

SONGS ASSET RETIREMENT OBLIGATIONS

Sempra, SDG&E

SDG&E’s legal AROs related to the decommissioning of SONGS are estimated based on a site-specific study performed no less than every three years. The estimate of the obligations includes:

▪ estimated decommissioning costs, including labor, equipment, material and other disposal costs

▪ inflation adjustment applied to estimated cash flows

▪ discount rate based on a credit-adjusted risk-free rate

▪ actual decommissioning costs, progress to date and expected duration of decommissioning activities

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SDG&E’s nuclear decommissioning expenses are subject to rate recovery and, therefore, rate-making accounting treatment is applied to SDG&E’s nuclear decommissioning activities. SDG&E recognizes a regulatory asset, or liability, to the extent that its SONGS ARO exceeds, or is less than, the amount collected from customers and the amount earned in SDG&E’s NDT.

SDG&E’s ARO related to the decommissioning of SONGS was $471 million as of December 31, 2024, based on the decommissioning cost study prepared in 2024. Changes in the estimated costs, execution strategy or timing of decommissioning, or in the assumptions and judgments by management underlying these estimates, could cause material revisions to the estimated total cost to decommission this facility, which could have a material effect on the recorded liability.

The following table illustrates the increase to SDG&E’s and Sempra’s ARO liability if the cost escalation rate was adjusted while leaving all other assumptions constant:

INCREASE TO ARO AND REGULATORY ASSET
(Dollars in millions)
	December 31, 2024
Uniform increase in escalation percentage of 1%	$	62

The increase in the ARO liability driven by an increase in the cost escalation rate would result in a decrease in the regulatory liability for recoveries in excess of ARO liabilities. We provide additional detail in Note 14 of the Notes to Consolidated Financial Statements.

IMPAIRMENT TESTING OF LONG-LIVED ASSETS

Sempra

Whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable, we consider if the estimated future undiscounted cash flows are less than the carrying amount of the asset. If so, we estimate the fair value of the asset to determine the extent to which carrying value exceeds fair value. For such an estimate, we may consider data from multiple valuation methods, including data from market participants. We exercise judgment to estimate the future cash flows and the useful life of a long-lived asset and to determine our intent to use the asset. Our intent to use or dispose of a long-lived asset is subject to re-evaluation and can change over time. If such an impairment test is required, the fair value of a long-lived asset can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. Critical assumptions that affect our estimates of fair value may include:

▪consideration of market transactions

▪future cash flows

▪the appropriate risk-adjusted discount rate, including the impacts of country risk and entity risk

We discuss impairment of long-lived assets in Note 1 of the Notes to Consolidated Financial Statements.

IMPAIRMENT TESTING OF GOODWILL

Sempra

When determining if goodwill is impaired, the fair value of the reporting unit can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. As a result, recognizing a goodwill impairment may or may not be required. When we perform a quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and compare that to its carrying value. Our fair value estimates are developed from the perspective of a knowledgeable market participant. We consider observable transactions in the marketplace for similar investments, if available, as well as an income-based approach such as a discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical assumptions that affect our estimates of fair value may include:

▪consideration of market transactions

▪future cash flows

▪projected revenue and expense growth rates

▪the appropriate risk-adjusted discount rate, including the impacts of country risk, customer creditworthiness and entity risk

2024 Form 10-K | 104

Historically, we determined based on a quantitative goodwill impairment test that the estimated fair values of our reporting units in Mexico, to which goodwill was allocated, were substantially above their respective carrying values as of October 1, our annual goodwill impairment testing date. Upon performing a qualitative analysis as of October 1, 2024, we determined that it was not more likely than not that the fair value of such reporting units was less than their respective carrying values. Our goodwill impairment test is determined based on assumptions existing as of that point in time. Changes in the business (such as loss of future cash flows from customer disputes, renegotiation of customer contracts or the macroeconomic environment, including rising interest rates) may result in us having to perform an interim goodwill impairment test, which could result in an impairment of our goodwill.

NEW ACCOUNTING STANDARDS

We discuss the recent accounting pronouncements that have had or may have a significant effect on our financial statements and/or disclosures in Note 2 of the Notes to Consolidated Financial Statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk of erosion of our cash flows, earnings, asset values or equity due to adverse changes in commodity market prices, interest rates and foreign currency and inflation rates.

MARKET RISK POLICIES

Sempra has policies governing its market risk management and trading activities. Sempra, SDG&E, SoCalGas and Sempra Infrastructure maintain separate risk management committees, organizations and processes to provide oversight of these activities for their respective businesses. The committees consist of senior officers who establish policy, oversee energy risk management activities, and monitor the results of trading and other activities to help ensure compliance with our energy risk management and trading policies. These activities include, but are not limited to, monitoring of market positions that create credit, liquidity and market risk. The respective oversight organizations and committees are independent from energy procurement departments.

Along with other tools, we use VaR and liquidity metrics to measure our exposure to market risk associated with commodity portfolios. VaR is an estimate of the potential loss on a position or portfolio of positions over a specified holding period, based on normal market conditions and within a given statistical confidence interval. We use a variance-covariance VaR model at a 95% confidence level. A liquidity metric is intended to monitor the amount of financial resources needed for meeting potential margin calls as forward market prices move. VaR and liquidity risk metrics are independently verified by the respective risk management oversight organizations.

SDG&E and SoCalGas use natural gas derivatives and SDG&E uses electricity derivatives to manage natural gas and electric price risk associated with servicing load requirements. The use of natural gas and electricity derivatives is subject to certain limitations imposed by company policy and regulatory requirements. SDG&E’s risk management and transacting activity plans for electricity derivatives are also required to be filed with, and have been approved by, the CPUC. SoCalGas is also subject to certain regulatory requirements and thresholds related to natural gas procurement under the GCIM. We discuss revenue recognition in Note 3 and additional market-risk information regarding derivative instruments in Note 9 of the Notes to Consolidated Financial Statements.

We have exposure to changes in commodity prices, interest rates and foreign currency and inflation rates. The following discussion of these primary market-risk exposures as of December 31, 2024 includes a discussion of how these exposures are managed.

COMMODITY PRICE RISK

Market risk related to physical commodities is created by volatility in the prices and basis of certain commodities. Our various subsidiaries are exposed, in varying degrees, to commodity price risk, primarily in the natural gas and electricity markets. Our policy is to manage this risk within a framework that considers the specific markets and operating and regulatory environments of each subsidiary.

Sempra Infrastructure is exposed to commodity price risk indirectly through its LNG, natural gas pipelines and storage, and power-generating assets. Sempra Infrastructure has utilized and may continue to utilize commodity contracts, including physical

2024 Form 10-K | 105

and financial derivatives, in an effort to mitigate these risks and optimize the value of these assets. These transactions are typically priced based on market indices but may also include fixed price purchases and sales of commodities. Any residual exposure is monitored as described above. Some of these derivatives that we use as economic hedges do not meet the requirements for hedge accounting, or hedge accounting is not elected, and as a result, the changes in fair value of these derivatives are recorded in earnings. Consequently, significant changes in commodity prices have in the past and could in the future result in earnings volatility as the economic offset of these derivatives may not be recorded at fair value. A significant decrease in the fair value of these economic hedges could also result in higher collateral requirements, which could negatively impact our liquidity and our ability to continue to mitigate our commodity risk exposure. We try to structure our hedging transactions with the objective that over time (i) realized gains and losses on our economic hedges would be largely offset by gains and losses related to our purchases or sales of natural gas and (ii) we would realize the economic benefit we anticipated at the time we structured the original transaction.

A hypothetical 10% change in commodity prices would have resulted in a change in the fair value of our commodity-based natural gas and electricity derivatives of $13 million and $14 million at December 31, 2024 and 2023, respectively. The impact of a change in energy commodity prices on our commodity-based derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled and does not typically include the generally offsetting impact of our underlying asset positions.

SDG&E and SoCalGas separately manage risk within the parameters of their market risk management frameworks. In addition, their market-risk exposure is limited due to CPUC-authorized rate recovery of the costs of commodity purchases, interstate and intrastate transportation, and storage activity. However, SoCalGas may, at times, be exposed to market risk as a result of the GCIM, which rewards or penalizes the utility for commodity costs below or above certain benchmarks. The one-day VaR for SDG&E’s and SoCalGas’ commodity positions were both $2 million at December 31, 2024 and $2 million and $4 million, respectively, at December 31, 2023.

INTEREST RATE RISK

We are exposed to fluctuations in interest rates primarily from our short- and long-term debt. Subject to regulatory constraints, we periodically enter into interest rate swap agreements to moderate our exposure to interest rate changes and to lower our overall cost of borrowing.

The table below shows the nominal amount of our debt:

NOMINAL AMOUNT OF DEBT(1)
(Dollars in millions)
	December 31, 2024						December 31, 2023
	Sempra		SDG&E		SoCalGas		Sempra		SDG&E		SoCalGas
Short-term:
Sempra California	$	1,454	$	417	$	1,037	$	947	$	—	$	947
Other	562		—		—		1,397		—		—
Long-term:
Sempra California fixed-rate	$	16,309	$	8,950	$	7,359	$	15,109	$	8,350	$	6,759
Sempra California variable-rate	—		—		—		400		400		—
Other fixed-rate	15,527		—		—		11,317		—		—
Other variable-rate	1,063		—		—		890		—		—

(1)    After the effects of interest rate swaps. Before reductions for unamortized discount and debt issuance costs and excluding finance lease obligations.

An interest rate risk sensitivity analysis measures interest rate risk by calculating the estimated changes in earnings attributable to common shares (but disregarding capitalized interest and impacts on equity earnings from debt at our equity method investees) that would result from a hypothetical change in market interest rates. Earnings attributable to common shares are affected by changes in interest rates on short-term debt and variable-rate long-term debt. If weighted-average interest rates on short-term debt outstanding at December 31, 2024 increased or decreased by 10%, the change in earnings attributable to common shares over the 12-month period ending December 31, 2025 would be approximately $7 million. If interest rates increased or decreased by 10% on all variable-rate long-term debt at December 31, 2024, after considering the effects of interest rate swaps, the change in earnings attributable to common shares over the 12-month period ending December 31, 2025 would be approximately $3 million.

We provide further information about debt and interest rate swap transactions in Notes 6 and 9, respectively, of the Notes to Consolidated Financial Statements.

2024 Form 10-K | 106

We also are subject to the effect of interest rate fluctuations on the assets of our pension plans, PBOP plans, and SDG&E’s NDT. However, we expect the effects of these fluctuations, as they relate to Sempra California, to be reflected in future rates.

FOREIGN CURRENCY EXCHANGE RATE RISK AND INFLATION EXPOSURE

We discuss our foreign currency exchange rate risk and inflation exposure in “Part II – Item 7. MD&A – Impact of Foreign Currency and Inflation Rates on Results of Operations.”

The hypothetical effect for every 10% appreciation in the U.S. dollar against the Mexican peso, in which we have operations and investments, are as follows:

HYPOTHETICAL EFFECTS FROM 10% STRENGTHENING OF U.S. DOLLAR (1)
(Dollars in millions)
	Hypothetical effects
Sempra:
Translation of 2024 earnings to U.S. dollars(2)	$	(2)
Transactional exposure(3)	151
Translation of net assets of foreign subsidiaries and investment in foreign entities(4)	(18)

(1)    After the effects of foreign currency derivatives.

(2)    Amount represents the impact to earnings for a change in the average exchange rate throughout the reporting period.

(3)    Amount primarily represents the effects of currency exchange rate movement from December 31, 2024 on monetary assets and liabilities and remeasurement of non-U.S. deferred income tax balances at our Mexican subsidiaries.

(4)    Amount represents the effects of currency exchange rate movement from December 31, 2024 that would be recorded to OCI at the end of the reporting period.

Monetary assets and liabilities at our Mexican subsidiaries and JVs that are denominated in U.S. dollars may fluctuate significantly throughout the year. These monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. Based on a net monetary liability position of $4.5 billion, including those related to our investments in JVs, at December 31, 2024, the hypothetical effect of a 10% increase in the Mexican inflation rate is approximately $89 million lower earnings attributable to common shares as a result of higher income tax expense for our consolidated entities, as well as lower equity earnings for our JVs.

In 2024 and 2023, SDG&E and SoCalGas experienced inflationary pressures from increases in various costs, including the cost of natural gas, electric fuel and purchased power, labor, materials and supplies, as well as availability of labor and materials. During this period, Sempra Texas Utilities experienced increased costs, including labor and contractor-related costs as well as higher insurance premiums, and does not have specific regulatory mechanisms that allow for recovery of higher non-reconcilable costs due to inflation; rather, recovery is limited to rate updates through capital trackers and base rate reviews, which may result in partial non-recovery due to the regulatory lag. If such costs continue to be subject to significant inflationary pressures and we are not able to fully recover such higher costs in rates or there is a delay in recovery, these increased costs may have a significant effect on Sempra’s, SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.

In 2024 and 2023, Sempra Infrastructure experienced inflationary pressures from increases in various costs, including the cost of labor, materials and supplies. Sempra Infrastructure generally secures long-term contracts that are U.S. dollar-denominated or referenced and are periodically adjusted for market factors, including inflation, and Sempra Infrastructure generally enters into lump-sum contracts for its large construction projects in which much of the risk during construction is absorbed or hedged by the EPC contractor. If additional costs become subject to significant inflationary pressures, we may not be able to fully recover such higher costs through contractual adjustments for inflation, which may have a significant effect on Sempra’s results of operations, financial condition, cash flows and/or prospects.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our consolidated financial statements are listed on the Index to Consolidated Financial Statements set forth on page F-1 of this annual report on Form 10-K.

2024 Form 10-K | 107

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Sempra, SDG&E, SoCalGas

Sempra, SDG&E and SoCalGas maintain disclosure controls and procedures designed to ensure that information required to be disclosed in their respective reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and is accumulated and communicated to the management of each company, including each respective principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, the management of each company recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives; therefore, the management of each company applies judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision and with the participation of the principal executive officers and principal financial officers of Sempra, SDG&E and SoCalGas, each such company’s management evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2024, the end of the period covered by this report. Based on these evaluations, the principal executive officers and principal financial officers of Sempra, SDG&E and SoCalGas concluded that their respective company’s disclosure controls and procedures were effective at the reasonable assurance level as of such date.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Sempra, SDG&E, SoCalGas

The respective management of Sempra, SDG&E and SoCalGas is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f).

Under the supervision and with the participation of the principal executive officers and principal financial officers of Sempra, SDG&E and SoCalGas, each such company’s management evaluated the effectiveness of its internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on these evaluations, each company’s management concluded that its internal control over financial reporting was effective as of December 31, 2024. Deloitte & Touche LLP audited the effectiveness of each company’s internal control over financial reporting as of December 31, 2024, as stated in their reports, which are included in this annual report on Form 10-K.

There have been no changes in Sempra’s, SDG&E’s or SoCalGas’ internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, any such company’s internal control over financial reporting.

2024 Form 10-K | 108

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Sempra:

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Sempra and subsidiaries (“Sempra”) as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, Sempra maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements as of and for the year ended December 31, 2024, of Sempra and our report dated February 25, 2025, expressed an unqualified opinion on those financial statements.

Basis for Opinion

Sempra’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Sempra’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sempra in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 25, 2025

2024 Form 10-K | 109

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholder and Board of Directors of San Diego Gas & Electric Company:

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of San Diego Gas & Electric Company (“SDG&E”) as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, SDG&E maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the financial statements as of and for the year ended December 31, 2024, of SDG&E and our report dated February 25, 2025, expressed an unqualified opinion on those financial statements.

Basis for Opinion

SDG&E’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on SDG&E’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to SDG&E in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 25, 2025

2024 Form 10-K | 110

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Southern California Gas Company:

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Southern California Gas Company (“SoCalGas”) as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, SoCalGas maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the financial statements as of and for the year ended December 31, 2024, of SoCalGas and our report dated February 25, 2025, expressed an unqualified opinion on those financial statements.

Basis for Opinion

SoCalGas’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on SoCalGas’ internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to SoCalGas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 25, 2025

2024 Form 10-K | 111

ITEM 9B. OTHER INFORMATION

(a)None.

(b)During the last fiscal quarter, no individual who was at the time a Sempra, SDG&E or SoCalGas director or officer, adopted or terminated a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement with respect to the securities of each such Registrant. As used herein, directors and officers are as defined in Rule 16a-1(f) under the Exchange Act, a Rule 10b5-1 trading arrangement is as defined in Item 408(a) of SEC Regulation S-K, and a non-Rule 10b5-1 trading arrangement is as defined in Item 408(c) of SEC Regulation S-K.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III.

Because SDG&E meets the conditions of General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this report with a reduced disclosure format as permitted by General Instruction I(2), the information required by Part III – Items 10, 11, 12 and 13 below is not required for SDG&E. We have, however, voluntarily provided the information required by Item 401 of SEC Regulation S-K, as required by Part III – Item 10 with respect to SDG&E’s executive officers in “Part I – Item 1. Business – Other Matters – Information About Our Executive Officers.”

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

We provide the information required by Item 401 of SEC Regulation S-K, as required by this item, with respect to executive officers of Sempra and SoCalGas in “Part I – Item 1. Business – Other Matters – Information About Our Executive Officers.” The other information required by this item is incorporated by reference from “Corporate Governance” and “Proposal 1: Election of Directors” in the proxy statement to be filed for the May 2025 annual meeting of shareholders for Sempra and from the information statement to be filed for the June 2025 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference. Sempra’s insider trading and information confidentiality policy is filed as Exhibit 19.1 to this report.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this item is incorporated by reference from “Executive Compensation,” including “Compensation Discussion and Analysis,” “Compensation and Talent Development Committee Report” and “Compensation Tables” (except for the disclosure under the heading “Pay-Versus-Performance”), in the proxy statement to be filed for the May 2025 annual meeting of shareholders for Sempra and from the information statement to be filed for the June 2025 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.

2024 Form 10-K | 112

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

Sempra has LTIPs that permit the grant of a wide variety of equity and equity-based incentive awards to directors, officers and key employees. At December 31, 2024, outstanding awards consisted of stock options and RSUs held by 457 employees.

The following table sets forth information regarding our equity compensation plans at December 31, 2024.

EQUITY COMPENSATION PLANS(1)
Equity compensation plans approved by shareholders	Number of shares to be issued upon exercise of outstanding options, warrants and rights(2)	Weighted-average exercise price of outstanding options, warrants and rights(3)		Number of additional shares remaining available for future issuance(4)
Sempra:
2013 LTIP	272,728	$	53.38	—
2019 LTIP	4,206,750	$	70.52	7,628,467

(1)    Excludes dividend equivalents.

(2)    The 2013 LTIP consists of 272,728 options to purchase shares of our common stock, all of which were granted at an exercise price equal to 100% of the grant date fair market value of the shares subject to the option. The 2019 LTIP consists of 1,757,938 options to purchase shares of our common stock, all of which were granted at an exercise price equal to 100% of the grant date fair market value of the shares subject to the option, 1,905,724 performance-based RSUs and 543,088 service-based RSUs. Each performance-based RSU granted under the 2019 LTIP represents the right to receive from 0% to 200% of the shares of our common stock represented by the RSUs, depending on the degree to which applicable performance conditions are satisfied. For purposes of this table, the number of shares of common stock shown to be subject to each performance-based RSU is 100% of the shares represented by the RSUs, which assumes performance conditions are satisfied at the target level.

(3)    Represents the weighted-average exercise price of the 272,728 and 1,757,938 outstanding options to purchase shares of our common stock under the 2013 LTIP and the 2019 LTIP, respectively.

(4)    The number of shares available for future issuance is increased by the number of shares to which each participant would otherwise be entitled that are withheld or surrendered to satisfy the exercise price or to satisfy tax withholding obligations relating to any plan awards, and is also increased by the number of shares subject to awards that expire or are forfeited, canceled or otherwise terminated without the issuance of shares. No new awards may be granted under the 2013 LTIP.

We provide additional discussion of share-based compensation in Note 13 of the Notes to Consolidated Financial Statements.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by Item 403 of SEC Regulation S-K, as required by this item, is incorporated by reference from “Share Ownership” in the proxy statement to be filed for the May 2025 annual meeting of shareholders for Sempra and from the information statement to be filed for the June 2025 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this item is incorporated by reference from “Corporate Governance” in the proxy statement to be filed for the May 2025 annual meeting of shareholders for Sempra and from the information statement to be filed for the June 2025 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.

2024 Form 10-K | 113

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information regarding principal accountant fees and services is presented below for Sempra, SDG&E and SoCalGas. The following table shows the fees paid to Deloitte & Touche LLP, the independent registered public accounting firm for Sempra, SDG&E and SoCalGas, for services provided for 2024 and 2023.

PRINCIPAL ACCOUNTANT FEES
(Dollars in thousands)
	Sempra				SDG&E				SoCalGas
	Fees		Percent of total		Fees		Percent of total		Fees		Percent of total
2024:
Audit fees:
Consolidated financial statements, internal controls audits and subsidiary audits	$	11,708			$	3,092			$	4,118
Regulatory filings and related services	798				75				150
Total audit fees	12,506		81	%	3,167		85	%	4,268		92	%
Audit-related fees:
Employee benefit plan audits	565				181				315
Other audit-related services(1)	2,101				190				20
Total audit-related fees	2,666		17		371		10		335		7
Tax fees(2)	299		2		178		5		47		1
All other fees(3)	40		—		—		—		—		—
Total fees	$	15,511	100	%	$	3,716	100	%	$	4,650	100	%
2023:
Audit fees:
Consolidated financial statements, internal controls audits and subsidiary audits	$	11,808			$	2,976			$	3,970
Regulatory filings and related services	513				170				85
Total audit fees	12,321		81	%	3,146		87	%	4,055		90	%
Audit-related fees:
Employee benefit plan audits	545				175				304
Other audit-related services(1)	1,643				175				115
Total audit-related fees	2,188		14		350		9		419		9
Tax fees(2)	668		5		135		4		46		1
All other fees(3)	59		—		—		—		—		—
Total fees	$	15,236	100	%	$	3,631	100	%	$	4,520	100	%

(1)    Other audit-related services primarily relate to statutory audits and agreed upon procedures.

(2)    Tax fees relate to tax consulting and compliance services.

(3)    All other fees relate to training and conferences.

The Audit Committee of Sempra’s board of directors is directly responsible for the appointment, compensation, retention and oversight, including the oversight of the audit fee negotiations, of the independent registered public accounting firm for Sempra and its subsidiaries, including SDG&E and SoCalGas. As a matter of good corporate governance, each of the Sempra, SDG&E and SoCalGas boards of directors reviewed the performance of Deloitte & Touche LLP and appointed them as the independent registered public accounting firm for each of Sempra, SDG&E and SoCalGas, respectively. Sempra’s board of directors has determined that each member of its Audit Committee is an independent director and is financially literate, and that Mr. Jack T. Taylor, who chairs the committee, and Ms. Jennifer M. Kirk, who is a member of the committee, are audit committee financial experts as defined by the rules of the SEC.

Except where pre-approval is not required by SEC rules, Sempra’s Audit Committee pre-approves all audit, audit-related and permissible non-audit services provided by Deloitte & Touche LLP for Sempra and its subsidiaries, including all services provided by Deloitte & Touche LLP for Sempra, SDG&E and SoCalGas in 2024 and 2023. The committee’s pre-approval policies and procedures provide for the general pre-approval of specific types of services and give detailed guidance to management as to the services that are eligible for general pre-approval, and they require specific pre-approval of all other permitted services. For both types of pre-approval, the committee considers whether the services to be provided are consistent with maintaining the firm’s independence. The committee’s policies and procedures also delegate authority to the Chair of the

2024 Form 10-K | 114

committee to address any requests for pre-approval of services between committee meetings, with any pre-approval decisions to be reported to the committee at its next scheduled meeting.

PART IV.

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are filed as part of this report: 

FINANCIAL STATEMENTS

Our consolidated financial statements are listed on the Index to Consolidated Financial Statements set forth on page F-1 of this annual report on Form 10-K.

FINANCIAL STATEMENT SCHEDULES

Schedule I is listed on the Index to Condensed Financial Information of Parent as set forth on page S-1 of this annual report on Form 10-K.

Any other schedule for which provision is made in SEC Regulation S-X is not required under the instructions contained therein, is inapplicable or the information is included in the Consolidated Financial Statements and Notes thereto in this annual report on Form 10-K.

2024 Form 10-K | 115

EXHIBITS

EXHIBIT INDEX

The exhibits listed below relate to each Registrant as indicated. Unless otherwise indicated, the exhibits that are incorporated by reference herein were filed under File Number 1-14201 (Sempra), File Number 1-40 (Pacific Lighting Corporation), File Number 1-03779 (San Diego Gas & Electric Company) and/or File Number 1-01402 (Southern California Gas Company). All exhibits to which Sempra is a party have been named in this Exhibit Index with Sempra’s current legal name (Sempra) rather than its former legal name (Sempra Energy) regardless of the date of the exhibit.

EXHIBIT INDEX
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
EXHIBIT 3 -- ARTICLES OF INCORPORATION AND BYLAWS
Sempra
3.1	Amended and Restated Articles of Incorporation of Sempra effective May 23, 2008.		10-K	3.1	02/27/20
3.2	Certificate of Determination of Preferences of 4.875% Fixed-Rate Reset Cumulative Redeemable Perpetual Stock, Series C, of Sempra (including the form of certificate representing the 4.875% Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, Series C), filed with the Secretary of State of California and effective June 11, 2020.		8-K	3.1	06/15/20
3.3	Certificate of Amendment of Amended and Restated Articles of Incorporation of Sempra dated May 12, 2023.		8-K	3.1	05/16/23
3.4	Bylaws of Sempra (as amended through May 12, 2023).		8-K	3.2	05/16/23
San Diego Gas & Electric Company
3.5	Amended and Restated Articles of Incorporation of San Diego Gas & Electric Company effective August 15, 2014.		10-K	3.4	02/26/15
3.6	Bylaws of San Diego Gas & Electric (as amended through October 26, 2016).		10-Q	3.1	11/02/16
Southern California Gas Company
3.7	Restated Articles of Incorporation of Southern California Gas Company effective October 7, 1996.		10-K	3.01	03/28/97
3.8	Bylaws of Southern California Gas Company (as amended through January 30, 2017).		8-K	3.1	01/31/17
EXHIBIT 4 -- INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS, INCLUDING INDENTURES
Certain instruments defining the rights of holders of long-term debt instruments are not required to be filed or incorporated by reference herein pursuant to Item 601(b)(4)(iii)(A) of SEC Regulation S-K. Each Registrant agrees to furnish a copy of such instruments to the SEC upon request.
Sempra
4.1	Description of rights of Sempra Common Stock (Amended and Restated Articles of Incorporation of Sempra effective May 23, 2008, as amended by the Certificate of Amendment of Amended and Restated Articles of Incorporation of Sempra dated May 12, 2023) (included as Exhibits 3.1 and 3.3 above).		10-K	3.1	02/27/20
4.2	Description of Securities.	X
4.3	Certificate of Determination of Preferences of 4.875% Fixed-Rate Reset Cumulative Redeemable Perpetual Stock, Series C, of Sempra (including the form of certificate representing the 4.875% Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, Series C), filed with the Secretary of State of California and effective June 11, 2020 (included as Exhibit 3.2 above).		8-K	3.1	06/15/20
4.4	Indenture dated as of February 23, 2000, between Sempra and U.S. Bank Trust National Association, as Trustee.		S-3ASR  333-153425	4.1	09/11/08

2024 Form 10-K | 116

EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
4.5	Officers’ Certificate of Sempra, including the form of its 6.00% Note due 2039.		8-K	4.1	10/08/09
4.6	Officers’ Certificate of Sempra, including the form of its 3.250% Note due 2027.		8-K	4.1	06/09/17
4.7	Officers’ Certificate of Sempra, including the forms of its 3.400% Note due 2028, its 3.800% Note due 2038, and its 4.000% Note due 2048.		8-K	4.1	01/12/18
4.8	Officers’ Certificate of Sempra, including the form of its 3.300% Note due 2025 and the form of its 3.700% Note due 2029.		8-K	4.1	03/24/22
4.9	Officers’ Certificate of Sempra, including the form of its 5.400% Note due 2026 and the form of its 5.500% Note due 2033.		8-K	4.1	06/23/23
4.10	Subordinated Indenture, dated as of June 26, 2019, between Sempra and U.S. Bank National Association, as trustee.		8-K	4.2	06/26/19
4.11	Officers’ Certificate of Sempra, including the form of its 5.750% Junior Subordinated Note due 2079.		8-K	4.1	06/26/19
4.12	Officers' Certificate of Sempra, including the form of its 4.125% Fixed-to-Fixed Reset Rate Junior Subordinated Note due 2052.		8-K	4.1	11/19/21
4.13	Officers’ Certificate of Sempra, including the form of 6.875% Fixed-to-Fixed Reset Rate Junior Subordinated Note due 2054.		8-K	4.1	03/14/24
4.14	Officers’ Certificate of Sempra, dated as of May 31, 2024, including the form of 6.875% Fixed-to-Fixed Reset Rate Junior Subordinated Note due 2054.		8-K	4.1	05/31/24
4.15	Officers’ Certificate of Sempra, dated as of September 9, 2024, including the form of 6.400% Fixed-to-Fixed Reset Rate Junior Subordinated Note due 2054.		8-K	4.1	09/09/24
4.16	Officers’ Certificate of Sempra, dated as of November 21, 2024, including the form of 6.625% Fixed-to-Fixed Reset Rate Junior Subordinated Note due 2055 and the form of 6.550% Fixed-to-Fixed Reset Rate Junior Subordinated Note due 2055.		8-K	4.1	11/21/24
Southern California Gas Company
4.17	Description of preferences of Preferred Stock, Preference Stock and Series Preferred Stock (Southern California Gas Company Restated Articles of Incorporation) (included as Exhibit 3.7 above).		10-K	3.01	03/28/97
4.18	Description of Securities.		10-K	4.9	02/27/20
Sempra / San Diego Gas & Electric Company
4.19	Mortgage and Deed of Trust dated July 1, 1940.		2-4769	B-3	(1)
4.20	Second Supplemental Indenture dated as of March 1, 1948.		2-7418	B-5B	(1)
4.21	Ninth Supplemental Indenture dated as of August 1, 1968.		333-52150	4.5	(1)
4.22	Tenth Supplemental Indenture dated as of December 1, 1968.		2-36042	2-K	(1)
4.23	Sixteenth Supplemental Indenture dated August 28, 1975.		33-34017	4.2	(1)
4.24	Fiftieth Supplemental Indenture, dated as of May 19, 2005.		8-K	4.1	05/19/05
4.25	Fifty-Second Supplemental Indenture, dated as of June 8, 2006.		8-K	4.1	06/08/06
4.26	Fifty-Fourth Supplemental Indenture, dated as of September 20, 2007.		8-K	4.1	09/20/07
4.27	Fifty-Fifth Supplemental Indenture, dated as of May 14, 2009.		8-K	4.1	05/15/09

(1) Exhibit is not available on the SEC’s website as it was filed in paper and predates the SEC’s Electronic Data Gathering, Analysis, and Retrieval (EDGAR) database.

2024 Form 10-K | 117

EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
4.28	Fifty-Sixth Supplemental Indenture, dated as of May 13, 2010.		8-K	4.1	05/13/10
4.29	Fifty-Seventh Supplemental Indenture, dated as of August 26, 2010.		8-K	4.1	08/26/10
4.30	Sixtieth Supplemental Indenture, dated as of November 17, 2011.		8-K	4.1	11/17/11
4.31	Sixty-First Supplemental Indenture, dated as of March 22, 2012.		8-K	4.1	03/23/12
4.32	Sixty-Fifth Supplemental Indenture, dated as of May 19, 2016.		8-K	4.1	05/19/16
4.33	Sixty-Sixth Supplemental Indenture, dated as of June 8, 2017.		8-K	4.1	06/08/17
4.34	Sixty-Seventh Supplemental Indenture, dated as of May 17, 2018.		8-K	4.1	05/17/18
4.35	Sixty-Eighth Supplemental Indenture, dated as of May 31, 2019.		8-K	4.1	05/31/19
4.36	Sixty-Ninth Supplemental Indenture, dated as of April 7, 2020.		8-K	4.1	04/07/20
4.37	Seventieth Supplemental Indenture, dated as of September 28, 2020.		8-K	4.1	09/28/20
4.38	Seventy-First Supplemental Indenture, dated as of August 13, 2021.		8-K	4.1	08/13/21
4.39	Seventy-Second Supplemental Indenture, dated as of March 11, 2022.		8-K	4.1	03/11/22
4.40	Seventy-Third Supplemental Indenture, dated as of March 11, 2022.		8-K	4.2	03/11/22
4.41	Seventy-Fourth Supplemental Indenture, dated as of March 10, 2023.		8-K	4.1	03/10/23
4.42	Seventy-Fifth Supplemental Indenture, dated as of August 11, 2023.		8-K	4.1	08/11/23
4.43	Seventy-Sixth Supplemental Indenture, dated as of March 22, 2024.		8-K	4.1	03/22/24
Sempra / Southern California Gas Company
4.44	First Mortgage Indenture of Southern California Gas Company to American Trust Company dated October 1, 1940.		2-4504	B-4	(1)
4.45	Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of July 1, 1947.		10-K	4.40	02/28/23
4.46	Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of August 1, 1955.		2-11997	4.07	(1)
4.47	Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of December 1, 1956.		10-K	4.09	02/23/07
4.48	Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank dated as of June 1, 1965.		10-K	4.10	02/23/07
4.49	Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of August 1, 1972.		2-59832	2.19	(1)
4.50	Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of May 1, 1976.		2-56034	2.20	(1)
4.51	Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of September 15, 1981.		333-70654	4.24	(1)
4.52	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of November 18, 2005.		8-K	4.1	11/18/05

(1) Exhibit is not available on the SEC’s website as it was filed in paper and predates EDGAR.

2024 Form 10-K | 118

EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
4.53	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of November 18, 2010.		8-K	4.1	11/18/10
4.54	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of September 21, 2012.		8-K	4.1	09/21/12
4.55	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of March 13, 2014.		8-K	4.1	03/13/14
4.56	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of June 18, 2015.		8-K	4.2	06/18/15
4.57	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of June 3, 2016.		8-K	4.1	06/03/16
4.58	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of May 15, 2018.		8-K	4.1	05/15/18
4.59	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of September 24, 2018.		8-K	4.1	09/24/18
4.60	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of June 4, 2019.		8-K	4.1	06/04/19
4.61	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of January 9, 2020.		8-K	4.1	01/09/20
4.62	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of March 29, 2022.		10-Q	4.5	05/05/22
4.63	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of November 14, 2022.		8-K	4.1	11/14/22
4.64	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of May 23, 2023.		8-K	4.1	05/23/23
4.65	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of May 23, 2023.		8-K	4.2	05/23/23
4.66	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of March 18, 2024.		8-K	4.1	03/18/24
4.67	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of August 14, 2024.		8-K	4.1	08/14/24
4.68	Indenture, dated as of May 1, 1989, between Southern California Gas Company and Citibank, N.A., as trustee.		333-28260	4.1.1	(1)
4.69	First Supplemental Indenture, dated as of October 1, 1992, between Southern California Gas Company and Citibank, N.A., as trustee.		8-K	4.1.2	(1)
4.70	Form of 5.670% Medium Term Note due 2028.		8-K	4.2.1	(1)
4.71	Senior Indenture, dated as of September 21, 2020, between Southern California Gas Company and U.S. Bank National Association, as trustee.		8-K	4.1	09/21/20
4.72	Officers’ Certificate of Southern California Gas Company, including the form of its 2.950% Note due 2027.		8-K	4.1	03/14/22

(1) Exhibit is not available on the SEC’s website as it was filed in paper and predates EDGAR.

2024 Form 10-K | 119

EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
EXHIBIT 10 -- MATERIAL CONTRACTS
Sempra
10.1	ATM Equity Offering Sales Agreement, dated November 6, 2024, among Sempra and Barclays Capital Inc., BofA Securities, Inc., Citigroup Global Markets Inc., Goldman Sachs & Co. LLC, J.P. Morgan Securities LLC, Mizuho Securities USA LLC, Morgan Stanley & Co. LLC, MUFG Securities Americas Inc., RBC Capital Markets, LLC, Scotia Capital (USA) Inc., and Wells Fargo Securities, LLC, as sales agents and forward sellers, and Barclays Bank PLC, Bank of America, N.A., Citibank, N.A., Goldman Sachs & Co. LLC, JPMorgan Chase Bank, National Association, Mizuho Markets Americas LLC, Morgan Stanley & Co. LLC, MUFG Securities EMEA plc, Royal Bank of Canada, The Bank of Nova Scotia and Wells Fargo Bank, National Association, as forward purchasers.		10-Q	10.1	11/06/24
Sempra / San Diego Gas & Electric Company / Southern California Gas Company
10.2	Form of Continental Forge and California Class Action Price Reporting Settlement Agreement dated as of January 4, 2006.		8-K	99.1	01/05/06
Sempra / San Diego Gas & Electric Company
10.3	Amended and Restated Operating Order between San Diego Gas & Electric Company and the California Department of Water Resources effective March 10, 2011.		10-Q	10.4	05/09/11
10.4	Amended and Restated Servicing Order between San Diego Gas & Electric Company and the California Department of Water Resources effective March 10, 2011.		10-Q	10.5	05/09/11
Sempra / Southern California Gas Company
10.5	Master Agreement to Resolve JCCP No. 4861 Private Party Claims, dated as of September 26, 2021, by and among Sempra, Southern California Gas Company, and the plaintiffs’ law firms listed on the signature pages thereto.		8-K	10.1	09/27/21
10.6	First Amendment to Master Agreement to Resolve JCCP No. 4861 Private Party Claims, dated as of July 15, 2022, by and among Sempra, Southern California Gas Company, and the plaintiffs’ law firms listed on the signature pages thereto.		10-Q	10.1	08/04/22
Management Contract or Compensatory Plan, Contract or Arrangement
Sempra / San Diego Gas & Electric Company / Southern California Gas Company
10.7	Form of Sempra 2019 Long-Term Incentive Plan 2024 and 2025 Nonqualified Stock Option Award Agreement.		10-K	10.8	02/27/24
10.8	Form of Sempra 2019 Long-Term Incentive Plan 2024 and 2025 Performance-Based Restricted Stock Unit Award - EPS Growth Performance Measure.		10-K	10.9	02/27/24
10.9	Form of Sempra 2019 Long-Term Incentive Plan 2024 and 2025 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure-S&P 500 Index.		10-K	10.10	02/27/24
10.10	Form of Sempra 2019 Long-Term Incentive Plan 2024 and 2025 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure-S&P 500 Utilities Index.		10-K	10.11	02/27/24
10.11	Form of Sempra 2019 Long-Term Incentive Plan 2024 and 2025 Time-Based Restricted Stock Unit Award - Two Year Award Vest.	X
10.12	Form of Sempra 2019 Long-Term Incentive Plan 2024 and 2025 Time-Based Restricted Stock Unit Award - Three Year Ratable Vest.		10-K	10.12	02/27/24
10.13	Form of Sempra 2019 Long-Term Incentive Plan 2024 Time-Based Restricted Stock Unit Award - Four Year Award Vest.		10-Q	10.2	11/06/24

2024 Form 10-K | 120

EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
10.14	Form of Sempra 2019 Long-Term Incentive Plan 2021, 2022 and 2023 Nonqualified Stock Option Award Agreement.		10-K	10.6	02/25/21
10.15	Form of Sempra 2019 Long-Term Incentive Plan 2023 Performance-Based Restricted Stock Unit Award - EPS Growth Performance Measure.		10-K	10.7	02/25/21
10.16	Form of Sempra 2019 Long-Term Incentive Plan 2023 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure-S&P 500 Index.		10-K	10.8	02/25/21
10.17	Form of Sempra 2019 Long-Term Incentive Plan 2023 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure-S&P 500 Utilities Index.		10-K	10.9	02/25/21
10.18	Form of Sempra 2019 Long-Term Incentive Plan 2023 Time-Based Restricted Stock Unit Award – Three Year Ratable Vest.		10-K	10.6	02/27/20
10.19	Form of Sempra 2019 Long-Term Incentive Plan 2022 and 2023 Time-Based Restricted Stock Unit Award - Four Year Award Vest.		10-Q	10.1	11/05/20
10.20	Form of Sempra 2019 Long-Term Incentive Plan 2020 Nonqualified Stock Option Award Agreement.		10-K	10.5	02/27/20
10.21	Amended and Restated Sempra 2019 Long-Term Incentive Plan.		10-Q	10.1	11/03/23
10.22	Form of Sempra 2013 Long-Term Incentive Plan 2019 Nonqualified Stock Option Award Agreement.		10-Q	10.1	05/07/19
10.23	Form of Indemnification Agreement with Directors and Executive Officers (executed before January 2011).		10-Q	10.2	08/07/08
10.24	Form of Indemnification Agreement with Directors and Executive Officers (executed after January 2011).		10-Q	10.1	05/04/16
10.25	Form of Sempra Shared Services Executive Incentive Compensation Plan.		10-K	10.19	02/27/14
10.26	Amendment Number 1 to the Amended and Restated Sempra 2013 Long-Term Incentive Plan.		10-K	10.26	02/25/21
10.27	Amended and Restated Sempra 2013 Long-Term Incentive Plan.		10-K	10.5	02/26/16
10.28	Amended and Restated Sempra Employee and Director Savings Plan, formerly known as the Sempra 2005 Deferred Compensation Plan.		10-Q	10.2	11/03/23
10.29	Amended and Restated Sempra Deferred Compensation and Excess Savings Plan.		10-K	10.28	02/28/17
10.30	2009 Amendment and Restatement of the Sempra Supplemental Executive Retirement Plan effective July 1, 2009.		10-K	10.28	02/26/16
10.31	First Amendment to the 2009 Amendment and Restatement of the Sempra Supplemental Executive Retirement Plan effective February 11, 2010.		10-K	10.29	02/26/16
10.32	Second Amendment to the 2009 Amendment and Restatement of the Sempra Supplemental Executive Retirement Plan effective January 1, 2014.		10-K	10.43	02/26/15
10.33	2015 Amendment and Restatement of the Sempra Cash Balance Restoration Plan effective November 10, 2015.		10-K	10.31	02/26/16
10.34	Sempra Amended and Restated Executive Life Insurance Plan.		10-K	10.22	02/26/13
10.35	Sempra Executive Personal Financial Planning Program Policy Document.		10-K	10.35	02/27/20

2024 Form 10-K | 121

EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
Sempra
10.36	Form of Sempra 2019 Long-Term Incentive Plan Non-Employee Directors’ Annual Restricted Stock Unit Award.		10-K	10.34	02/27/24
10.37	Form of Sempra 2019 Long-Term Incentive Plan Non-Employee Directors’ Initial Restricted Stock Unit Award.		10-K	10.35	02/27/24
10.38	Sempra Amended and Restated Retirement Plan for Directors.		10-Q	10.7	08/07/08
10.39	Sempra Annual Incentive Plan.		10-Q	10.7	05/07/18
10.40	Severance Pay Agreement between Sempra and Justin C. Bird, signed January 24, 2024 and effective January 1, 2024.		10-K	10.38	02/27/24
10.41	Severance Pay Agreement between Sempra and Diana L. Day, signed March 8, 2023 and effective March 1, 2023.		10-K	10.39	02/27/24
10.42	Severance Pay Agreement between Sempra and Lisa M. Larroque Alexander, signed March 8, 2023 and effective March 1, 2023.	X
10.43	Amended and Restated Severance Pay Agreement between Sempra and Jeffrey W. Martin, signed January 4, 2023 and effective January 1, 2023.		10-K	10.38	02/28/23
10.44	Amendment to Severance Pay Agreement, dated February 20, 2025, between Sempra and Jeffrey W. Martin.		8-K	10.1	02/20/25
10.45	Amended and Restated Severance Pay Agreement between Sempra and Karen L. Sedgwick, signed January 25, 2024 and effective January 1, 2024.		10-K	10.42	02/27/24
10.46	Amended and Restated Severance Pay Agreement between Sempra and Peter R. Wall, signed January 3, 2023 and effective January 1, 2023.		10-K	10.41	02/28/23
10.47*	Letter Agreement from Sempra Infrastructure to Justin C. Bird dated April 18, 2023.	X
10.48*	Aircraft Time Sharing Agreement, effective March 11, 2024, between Sempra and Jeffrey W. Martin.		10-Q	10.11	05/07/24
10.49	Sempra Cash Severance Payments Policy.		10-Q	10.12	05/07/24
Sempra / San Diego Gas & Electric Company
10.50	Form of San Diego Gas & Electric Company Executive Incentive Compensation Plan.		10-K	10.64	02/27/14
10.51	Amended and Restated Severance Pay Agreement between Sempra and Valerie A. Bille, signed March 8, 2023 and effective March 1, 2023.		10-Q	10.7	05/04/23
10.52	Severance Pay Agreement between Sempra and Scott Crider, signed March 8, 2023 and effective March 1, 2023.	X
10.53	Amended and Restated Severance Pay Agreement between Sempra and Bruce A. Folkmann, signed March 8, 2023 and effective March 1, 2023.		10-Q	10.8	05/04/23
10.54	Amended and Restated Severance Pay Agreement between Sempra and Kevin C. Geraghty, signed March 6, 2023 and effective March 1, 2023.		10-Q	10.9	05/04/23

* Portions of the exhibit have been omitted in accordance with applicable SEC rules.

2024 Form 10-K | 122

EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
10.55	Amended and Restated Severance Pay Agreement between Sempra and Erbin Keith, signed March 10, 2023 and effective as of March 1, 2023.		10-Q	10.10	05/04/23
10.56	Amended and Restated Severance Pay Agreement between Sempra and Caroline A. Winn, signed March 8, 2023 and effective March 1, 2023.		10-Q	10.11	05/04/23
Sempra / Southern California Gas Company
10.57	Form of Southern California Gas Company Executive Incentive Compensation Plan.		10-K	10.71	02/27/14
10.58	Amended and Restated Severance Pay Agreement between Sempra and David J. Barrett, signed March 9, 2023 and effective March 1, 2023.		10-Q	10.12	05/04/23
10.59	Amended and Restated Severance Pay Agreement between Sempra and Maryam S. Brown, signed January 22, 2025 and effective January 1, 2025.	X
10.60	Amended and Restated Severance Pay Agreement between Sempra and Jimmie I. Cho, signed March 8, 2023 and effective March 1, 2023.		10-Q	10.14	05/04/23
10.61	Amended and Restated Severance Pay Agreement between Sempra and Mia L. DeMontigny, signed March 8, 2023 and effective March 1, 2023.		10-Q	10.15	05/04/23
10.62	Severance Pay Agreement between Sempra and Sara P. Mijares, signed March 8, 2023 and effective March 1, 2023.		10-Q	10.1	08/06/24
EXHIBIT 14 -- CODE OF ETHICS
Sempra / San Diego Gas & Electric Company / Southern California Gas Company
14.1	Sempra Code of Business Conduct and Ethics for Directors and Principal and Executive Officers (also applies to Principal Officers of San Diego Gas & Electric Company and Southern California Gas Company).		10-K	14.1	02/25/22
EXHIBIT 19 -- INSIDER TRADING POLICIES AND PROCEDURES
Sempra / San Diego Gas & Electric Company / Southern California Gas Company
19.1	Insider Trading and Information Confidentiality Policy.	X

2024 Form 10-K | 123

EXHIBIT INDEX (CONTINUED)
Exhibit Number	Exhibit Description	Filed or Furnished Herewith
EXHIBIT 21 -- SUBSIDIARIES
Sempra
21.1	Sempra Schedule of Certain Subsidiaries at December 31, 2024.	X
EXHIBIT 23 -- CONSENTS OF EXPERTS AND COUNSEL
Sempra
23.1	Sempra Consent of Independent Registered Public Accounting Firm.	X
23.2	Oncor Electric Delivery Holdings Company LLC Consent of Independent Auditors.	X
San Diego Gas & Electric Company
23.3	San Diego Gas & Electric Company Consent of Independent Registered Public Accounting Firm.	X
Southern California Gas Company
23.4	Southern California Gas Company Consent of Independent Registered Public Accounting Firm.	X
EXHIBIT 24 -- POWERS OF ATTORNEY
Sempra
24.1	Power of attorney of Sempra signatories (incorporated by reference to the signature page hereto).	X
San Diego Gas & Electric Company
24.2	Power of attorney of San Diego Gas & Electric Company signatories (incorporated by reference to the signature page hereto).	X
Southern California Gas Company
24.3	Power of attorney of Southern California Gas Company signatories (incorporated by reference to the signature page hereto).	X
EXHIBIT 31 -- SECTION 302 CERTIFICATIONS
Sempra
31.1	Certification of Sempra’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.	X
31.2	Certification of Sempra’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.	X
San Diego Gas & Electric Company
31.3	Certification of San Diego Gas & Electric Company’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.	X
31.4	Certification of San Diego Gas & Electric Company’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.	X
Southern California Gas Company
31.5	Certification of Southern California Gas Company’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.	X
31.6	Certification of Southern California Gas Company’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.	X

2024 Form 10-K | 124

EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
EXHIBIT 32 -- SECTION 906 CERTIFICATIONS
Sempra
32.1	Certification of Sempra’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.	X
32.2	Certification of Sempra’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.	X
San Diego Gas & Electric Company
32.3	Certification of San Diego Gas & Electric Company’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.	X
32.4	Certification of San Diego Gas & Electric Company’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.	X
Southern California Gas Company
32.5	Certification of Southern California Gas Company’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.	X
32.6	Certification of Southern California Gas Company’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.	X
EXHIBIT 97 -- POLICY RELATING TO RECOVERY OF ERRONEOUSLY AWARDED COMPENSATION
Sempra / San Diego Gas & Electric Company / Southern California Gas Company
97.1	Compensation Recovery Policy.		10-K	97.1	2/27/24
EXHIBIT 99 -- ADDITIONAL EXHIBITS
Sempra
99.1	Audited consolidated financial statements of Oncor Electric Delivery Holdings Company LLC and subsidiaries as of December 31, 2024 and 2023 for each of the three years ended in the period ended December 31, 2024, and the related Independent Auditors’ Report.	X
EXHIBIT 101 -- INTERACTIVE DATA FILE
101.INS	XBRL Instance Document - the instance document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document.	X
101.SCH	XBRL Taxonomy Extension Schema Document.	X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.	X
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.	X
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.	X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.	X
EXHIBIT 104 -- COVER PAGE
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

2024 Form 10-K | 125

ITEM 16. FORM 10-K SUMMARY

Not applicable.

2024 Form 10-K | 126

Sempra:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
	SEMPRA, (Registrant)
	By:  /s/ J. Walker Martin
	J. Walker Martin Chairman, Chief Executive Officer and President
	Date: February 25, 2025
POWER OF ATTORNEY
Each of the undersigned officers and directors of the registrant hereby severally constitutes and appoints each individual who, at the time of acting under this power of attorney, is the Principal Executive Officer (however designated), the Principal Financial Officer (however designated) or the Principal Accounting Officer (however designated) of Sempra, and each of them singly (with full power to each of them to act alone), as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution in each of them, for him or her and in his or her name, place and stead, and in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits thereto and other documents in connection therewith, with the U.S. Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof. This power of attorney shall be governed by and construed in accordance with the laws of the State of California and applicable federal securities laws. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

Name/Title	Signature	Date
Principal Executive Officer: J. Walker Martin Chief Executive Officer and President	/s/ J. Walker Martin	February 25, 2025
Principal Financial Officer: Karen L. Sedgwick Executive Vice President and Chief Financial Officer	/s/ Karen L. Sedgwick	February 25, 2025
Principal Accounting Officer: Peter R. Wall Senior Vice President, Controller and Chief Accounting Officer	/s/ Peter R. Wall	February 25, 2025

2024 Form 10-K | 127

Directors:	Signature	Date
J. Walker Martin, Chairman	/s/ J. Walker Martin	February 25, 2025
Andrés Conesa, Director	/s/ Andrés Conesa	February 25, 2025
Pablo A. Ferrero, Director	/s/ Pablo A. Ferrero	February 25, 2025
Jennifer M. Kirk, Director	/s/ Jennifer M. Kirk	February 25, 2025
Richard J. Mark, Director	/s/ Richard J. Mark	February 25, 2025
Michael N. Mears, Director	/s/ Michael N. Mears	February 25, 2025
Jack T. Taylor, Director	/s/ Jack T. Taylor	February 25, 2025
Cynthia J. Warner, Director	/s/ Cynthia J. Warner	February 25, 2025
James C. Yardley, Director	/s/ James C. Yardley	February 25, 2025

2024 Form 10-K | 128

San Diego Gas & Electric Company:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
	SAN DIEGO GAS & ELECTRIC COMPANY, (Registrant)
	By:  /s/ Caroline A. Winn
	Caroline A. Winn Chief Executive Officer
	Date: February 25, 2025
POWER OF ATTORNEY
Each of the undersigned officers and directors of the registrant hereby severally constitutes and appoints each individual who, at the time of acting under this power of attorney, is the Principal Executive Officer (however designated), the Principal Financial Officer (however designated) or the Principal Accounting Officer (however designated) of San Diego Gas & Electric Company, and each of them singly (with full power to each of them to act alone), as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution in each of them, for him or her and in his or her name, place and stead, and in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits thereto and other documents in connection therewith, with the U.S. Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof. This power of attorney shall be governed by and construed in accordance with the laws of the State of California and applicable federal securities laws. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

Name/Title	Signature	Date
Principal Executive Officer: Caroline A. Winn Chief Executive Officer	/s/ Caroline A. Winn	February 25, 2025
Principal Financial Officer: Bruce A. Folkmann Chief Financial Officer	/s/ Bruce A. Folkmann	February 25, 2025
Principal Accounting Officer: Valerie A. Bille Vice President, Controller and Chief Accounting Officer	/s/ Valerie A. Bille	February 25, 2025

2024 Form 10-K | 129

Directors:	Signature	Date
Karen L. Sedgwick, Non-Executive Chairman	/s/ Karen L. Sedgwick	February 25, 2025
Robert J. Borthwick, Director	/s/ Robert J. Borthwick	February 25, 2025
Diana L. Day, Director	/s/ Diana L. Day	February 25, 2025
Glen A. Donovan, Director	/s/ Glen A. Donovan	February 25, 2025
Caroline A. Winn, Director	/s/ Caroline A. Winn	February 25, 2025

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT:

No annual report to security holders covering the registrant’s last fiscal year and no proxy statement, form of proxy or other proxy soliciting material with respect to any annual or other meeting of security holders has been sent to security holders during the period covered by this annual report on Form 10-K, and no such materials are to be furnished to security holders subsequent to the filing of this annual report on Form 10-K.

2024 Form 10-K | 130

Southern California Gas Company:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
	SOUTHERN CALIFORNIA GAS COMPANY, (Registrant)
	By:  /s/ Maryam S. Brown
	Maryam S. Brown Chief Executive Officer and President
	Date: February 25, 2025
POWER OF ATTORNEY
Each of the undersigned officers and directors of the registrant hereby severally constitutes and appoints each individual who, at the time of acting under this power of attorney, is the Principal Executive Officer (however designated), the Principal Financial Officer (however designated) or the Principal Accounting Officer (however designated) of Southern California Gas Company, and each of them singly (with full power to each of them to act alone), as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution in each of them, for him or her and in his or her name, place and stead, and in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits thereto and other documents in connection therewith, with the U.S. Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof. This power of attorney shall be governed by and construed in accordance with the laws of the State of California and applicable federal securities laws. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

Name/Title	Signature	Date
Principal Executive Officer: Maryam S. Brown Chief Executive Officer and President	/s/ Maryam S. Brown	February 25, 2025
Principal Financial Officer: Mia L. DeMontigny Senior Vice President and Chief Financial Officer	/s/ Mia L. DeMontigny	February 25, 2025
Principal Accounting Officer: Sara P. Mijares Vice President, Controller and Chief Accounting Officer	/s/ Sara P. Mijares	February 25, 2025
Directors:
Karen L. Sedgwick, Non-Executive Chairman	/s/ Karen L. Sedgwick	February 25, 2025
Maryam S. Brown, Director	/s/ Maryam S. Brown	February 25, 2025
Diana L. Day, Director	/s/ Diana L. Day	February 25, 2025
Lisa M. Larroque Alexander, Director	/s/ Lisa M. Larroque Alexander	February 25, 2025
Peter R. Wall, Director	/s/ Peter R. Wall	February 25, 2025

2024 Form 10-K | 131

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Reports of Independent Registered Public Accounting Firm (PCAOB ID 34)			F-2
Consolidated Financial Statements:	Sempra	San Diego Gas & Electric Company	Southern California Gas Company
Consolidated Statements of Operations for the years ended December 31, 2024, 2023 and 2022	F-8	F-15	F-21
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2024, 2023 and 2022	F-9	F-16	F-22
Consolidated Balance Sheets at December 31, 2024 and 2023	F-10	F-17	F-23
Consolidated Statements of Cash Flows for the years ended December 31, 2024, 2023 and 2022	F-12	F-19	F-25
Consolidated Statements of Changes in Equity for the years ended December 31, 2024, 2023 and 2022	F-14	N/A	N/A
Statements of Changes in Shareholders Equity for the years ended December 31, 2024, 2023 and 2022	N/A	F-20	F-26
Notes to Consolidated Financial Statements
Note 1. Significant Accounting Policies and Other Financial Data			F-27
Note 2. New Accounting Standards			F-50
Note 3. Revenues			F-51
Note 4. Regulatory Matters			F-57
Note 5. Sempra – Investments in Unconsolidated Entities			F-60
Note 6. Debt and Credit Facilities			F-65
Note 7. Income Taxes			F-74
Note 8. Employee Benefit Plans			F-81
Note 9. Derivative Financial Instruments			F-99
Note 10. Fair Value Measurements			F-106
Note 11. Preferred Stock			F-111
Note 12. Sempra – Equity and Earnings Per Common Share			F-114
Note 13. Share-Based Compensation			F-118
Note 14. San Onofre Nuclear Generating Station			F-122
Note 15. Commitments and Contingencies			F-124
Note 16. Segment Information			F-138

2024 Form 10-K | F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Sempra:

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Sempra and subsidiaries (“Sempra”) as of December 31, 2024 and 2023, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2024, the related notes, and the schedule listed in Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of Sempra as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), Sempra’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2025, expressed an unqualified opinion on Sempra’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of Sempra’s management. Our responsibility is to express an opinion on Sempra’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sempra in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Accounting – Impact of Rate Regulation on the Financial Statements – Refer to Note 1 of the Notes to Financial Statements

Critical Audit Matter Description

Sempra is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of electric and gas transmission and distribution companies in those jurisdictions. Management has determined it meets the requirements under U.S. GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

We identified the impact of rate regulation as a critical audit matter due to the high degree of subjectivity involved in assessing the impact of regulatory orders and future actions by the Commissions on the financial statements. Management’s judgments include assessing the likelihood of (1) the recovery in future rates of incurred costs and (2) potential refunds to customers. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

2024 Form 10-K | F-2

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation and the uncertainty of future decisions by the Commissions included the following, among others:

▪We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

▪We read relevant regulatory orders issued by the Commissions for Sempra and other publicly available information to assess the likelihood of recovery in future rates, or of a future reduction in rates, based on precedents of the Commissions’ treatment of similar costs under similar circumstances.

▪We evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness.

▪We evaluated Sempra’s disclosures related to the impacts of rate regulation.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 25, 2025

We have served as Sempra’s auditor since 1935.

2024 Form 10-K | F-3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholder and Board of Directors of San Diego Gas & Electric Company:

Opinion on the Financial Statements

We have audited the accompanying balance sheets of San Diego Gas & Electric Company (“SDG&E”) as of December 31, 2024 and 2023, the related statements of operations, comprehensive income (loss), changes in shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of SDG&E as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), SDG&E’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2025, expressed an unqualified opinion on SDG&E’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of SDG&E’s management. Our responsibility is to express an opinion on SDG&E’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to SDG&E in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Accounting – Impact of Rate Regulation on the Financial Statements – Refer to Note 1 of the Notes to Financial Statements

Critical Audit Matter Description

SDG&E is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of electric and gas transmission and distribution companies in those jurisdictions. Management has determined it meets the requirements under U.S. GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

We identified the impact of rate regulation as a critical audit matter due to the high degree of subjectivity involved in assessing the impact of regulatory orders and future actions by the Commissions on the financial statements. Management’s judgments include assessing the likelihood of (1) the recovery in future rates of incurred costs and (2) potential refunds to customers. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

2024 Form 10-K | F-4

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation and the uncertainty of future decisions by the Commissions included the following, among others:

▪We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

▪We read relevant regulatory orders issued by the Commissions for SDG&E and other publicly available information to assess the likelihood of recovery in future rates, or of a future reduction in rates, based on precedents of the Commissions’ treatment of similar costs under similar circumstances.

▪We evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness.

▪We evaluated SDG&E’s disclosures related to the impacts of rate regulation.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 25, 2025

We have served as SDG&E’s auditor since 1935.

2024 Form 10-K | F-5

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Southern California Gas Company:

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Southern California Gas Company (“SoCalGas”) as of December 31, 2024 and 2023, the related statements of operations, comprehensive income (loss), changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of SoCalGas as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), SoCalGas’ internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2025, expressed an unqualified opinion on SoCalGas’ internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of SoCalGas’ management. Our responsibility is to express an opinion on SoCalGas’ financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to SoCalGas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Accounting – Impact of Rate Regulation on the Financial Statements – Refer to Note 1 of the Notes to Financial Statements

Critical Audit Matter Description

SoCalGas is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of gas transmission and distribution companies in those jurisdictions. Management has determined it meets the requirements under U.S. GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

We identified the impact of rate regulation as a critical audit matter due to the high degree of subjectivity involved in assessing the impact of regulatory orders and future actions by the Commissions on the financial statements. Management’s judgments include assessing the likelihood of (1) the recovery in future rates of incurred costs and (2) potential refunds to customers. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

2024 Form 10-K | F-6

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation and the uncertainty of future decisions by the Commissions included the following, among others:

▪We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

▪We read relevant regulatory orders issued by the Commissions for SoCalGas and other publicly available information to assess the likelihood of recovery in future rates, or of a future reduction in rates, based on precedents of the Commissions’ treatment of similar costs under similar circumstances.

▪We evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness.

▪We evaluated SoCalGas’ disclosures related to the impacts of rate regulation.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 25, 2025

We have served as SoCalGas’ auditor since 1937.

2024 Form 10-K | F-7

SEMPRA
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts; shares in thousands)
	Years ended December 31,
	2024		2023		2022
REVENUES
Utilities:
Natural gas	$	7,141	$	9,495	$	7,868
Electric	4,296		4,334		4,783
Energy-related businesses	1,748		2,891		1,788
Total revenues	13,185		16,720		14,439
EXPENSES AND OTHER INCOME
Utilities:
Cost of natural gas	(1,132)		(3,719)		(2,603)
Cost of electric fuel and purchased power	(245)		(375)		(937)
Energy-related businesses cost of sales	(380)		(548)		(942)
Operation and maintenance	(5,336)		(5,458)		(4,746)
Aliso Canyon litigation and regulatory matters	—		—		(259)
Depreciation and amortization	(2,437)		(2,227)		(2,019)
Franchise fees and other taxes	(693)		(677)		(635)
Other income, net	136		131		24
Interest income	61		89		75
Interest expense	(1,049)		(1,309)		(1,054)
Income before income taxes and equity earnings	2,110		2,627		1,343
Income tax expense	(219)		(490)		(556)
Equity earnings	1,609		1,481		1,498
Net income	3,500		3,618		2,285
Earnings attributable to noncontrolling interests	(638)		(543)		(146)
Preferred dividends	(44)		(44)		(44)
Preferred dividends of subsidiary	(1)		(1)		(1)
Earnings attributable to common shares	$	2,817	$	3,030	$	2,094
Basic EPS:
Earnings	$	4.44	$	4.81	$	3.32
Weighted-average common shares outstanding	633,795		630,296		630,318
Diluted EPS:
Earnings	$	4.42	$	4.79	$	3.31
Weighted-average common shares outstanding	637,943		632,733		632,757

See Notes to Consolidated Financial Statements.

2024 Form 10-K | F-8

SEMPRA
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Years ended December 31, 2024, 2023 and 2022
	Sempra shareholders’ equity
	Pretax amount		Income tax (expense) benefit		Net-of-tax amount		Noncontrolling interests (after tax)		Total
2024:
Net income	$	3,081	$	(219)	$	2,862	$	638	$	3,500
Other comprehensive income (loss):
Foreign currency translation adjustments	(30)		—		(30)		(14)		(44)
Financial instruments	14		(2)		12		25		37
Pension and other postretirement benefits	18		(16)		2		—		2
Total other comprehensive income (loss)	2		(18)		(16)		11		(5)
Comprehensive income	3,083		(237)		2,846		649		3,495
Preferred dividends of subsidiary	(1)		—		(1)		—		(1)
Comprehensive income, after preferred dividends of subsidiary	$	3,082	$	(237)	$	2,845	$	649	$	3,494
2023:
Net income	$	3,565	$	(490)	$	3,075	$	543	$	3,618
Other comprehensive income (loss):
Foreign currency translation adjustments	23		—		23		10		33
Financial instruments	57		(18)		39		(38)		1
Pension and other postretirement benefits	(39)		8		(31)		—		(31)
Total other comprehensive income (loss)	41		(10)		31		(28)		3
Comprehensive income	3,606		(500)		3,106		515		3,621
Preferred dividends of subsidiary	(1)		—		(1)		—		(1)
Comprehensive income, after preferred dividends of subsidiary	$	3,605	$	(500)	$	3,105	$	515	$	3,620
2022:
Net income	$	2,695	$	(556)	$	2,139	$	146	$	2,285
Other comprehensive income (loss):
Foreign currency translation adjustments	11		—		11		4		15
Financial instruments	221		(55)		166		50		216
Pension and other postretirement benefits	3		(6)		(3)		—		(3)
Total other comprehensive income	235		(61)		174		54		228
Comprehensive income	2,930		(617)		2,313		200		2,513
Preferred dividends of subsidiary	(1)		—		(1)		—		(1)
Comprehensive income, after preferred dividends of subsidiary	$	2,929	$	(617)	$	2,312	$	200	$	2,512

See Notes to Consolidated Financial Statements.

2024 Form 10-K | F-9

SEMPRA
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31,
	2024		2023
ASSETS
Current assets:
Cash and cash equivalents	$	1,565	$	236
Restricted cash	21		49
Accounts receivable – trade, net	1,983		2,151
Accounts receivable – other, net	397		561
Due from unconsolidated affiliates	13		31
Income taxes receivable	90		94
Inventories	559		482
Prepaid expenses	255		273
Regulatory assets	60		226
Fixed-price contracts and other derivatives	91		122
Greenhouse gas allowances	217		1,189
Other current assets	34		56
Total current assets	5,285		5,470
Other assets:
Restricted cash	3		104
Regulatory assets	3,937		3,771
Greenhouse gas allowances	845		301
Nuclear decommissioning trusts	875		872
Dedicated assets in support of certain benefit plans	585		549
Deferred income taxes	172		129
Right-of-use assets – operating leases	1,177		723
Investment in Oncor Holdings	15,400		14,266
Other investments	2,534		2,244
Goodwill	1,602		1,602
Other intangible assets	292		318
Wildfire fund	262		269
Other long-term assets	1,749		1,603
Total other assets	29,433		26,751
Property, plant and equipment:
Property, plant and equipment	80,397		72,495
Less accumulated depreciation and amortization	(18,960)		(17,535)
Property, plant and equipment, net	61,437		54,960
Total assets	$	96,155	$	87,181

See Notes to Consolidated Financial Statements.

2024 Form 10-K | F-10

SEMPRA
CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	December 31,
	2024		2023
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$	2,016	$	2,342
Accounts payable – trade	2,238		2,211
Accounts payable – other	208		224
Due to unconsolidated affiliates	—		5
Dividends and interest payable	773		691
Accrued compensation and benefits	558		526
Regulatory liabilities	141		553
Current portion of long-term debt and finance leases	2,274		975
Greenhouse gas obligations	217		1,189
Other current liabilities	1,251		1,374
Total current liabilities	9,676		10,090
Long-term debt and finance leases	31,558		27,759
Deferred credits and other liabilities:
Due to unconsolidated affiliates	352		307
Regulatory liabilities	3,817		3,739
Greenhouse gas obligations	506		—
Pension and other postretirement benefit plan obligations, net of plan assets	168		407
Deferred income taxes	5,845		5,254
Asset retirement obligations	3,737		3,642
Deferred credits and other	2,708		2,329
Total deferred credits and other liabilities	17,133		15,678
Commitments and contingencies (Note 15)
Equity:
Preferred stock (50,000,000 shares authorized; 900,000 shares of series C outstanding)	889		889
Common stock (1,125,000,000 shares authorized; 650,629,876 and 631,431,732 shares outstanding at December 31, 2024 and 2023, respectively; no par value)	13,520		12,204
Retained earnings	16,979		15,732
Accumulated other comprehensive income (loss)	(166)		(150)
Total Sempra shareholders’ equity	31,222		28,675
Preferred stock of subsidiary	20		20
Other noncontrolling interests	6,546		4,959
Total equity	37,788		33,654
Total liabilities and equity	$	96,155	$	87,181

See Notes to Consolidated Financial Statements.

2024 Form 10-K | F-11

SEMPRA
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	3,500	$	3,618	$	2,285
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	2,437		2,227		2,019
Deferred income taxes and investment tax credits	(20)		249		392
Equity earnings	(1,609)		(1,481)		(1,498)
Share-based compensation expense	86		80		71
Fixed-price contracts and other derivatives	(197)		(666)		863
Bad debt expense	209		458		122
Other	20		(14)		56
Net change in working capital components:
Accounts receivable	118		168		(976)
Due to/from unconsolidated affiliates, net	30		26		(31)
Income taxes receivable/payable, net	(49)		142		(29)
Inventories	(74)		(80)		(17)
Other current assets	(30)		11		(1,608)
Accounts payable	(131)		(270)		430
Regulatory balancing accounts, net	(456)		260		36
Reserve for Aliso Canyon costs	(12)		(98)		(1,851)
Other current liabilities	142		1,270		228
Insurance receivable for Aliso Canyon costs	—		—		360
Distributions from investments	1,093		912		854
Changes in other noncurrent assets and liabilities, net	(150)		(594)		(564)
Net cash provided by operating activities	4,907		6,218		1,142
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(8,215)		(8,397)		(5,357)
Expenditures for investments	(988)		(382)		(376)
Distributions from investments	9		—		—
Purchases of nuclear decommissioning and other trust assets	(889)		(610)		(700)
Proceeds from sales of nuclear decommissioning and other trust assets	942		661		762
Repayments of advances to unconsolidated affiliates	—		—		626
Other	23		12		6
Net cash used in investing activities	$	(9,118)	$	(8,716)	$	(5,039)

See Notes to Consolidated Financial Statements.

2024 Form 10-K | F-12

SEMPRA
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid	$	(1,499)	$	(1,483)	$	(1,430)
Preferred dividends paid	(44)		(44)		(44)
Issuances of common stock, net	1,219		145		4
Repurchases of common stock	(43)		(32)		(478)
Issuances of debt (maturities greater than 90 days)	8,674		7,669		9,984
Payments on debt (maturities greater than 90 days) and finance leases	(3,339)		(6,294)		(4,510)
(Decrease) increase in short-term debt, net	(557)		552		(1,266)
Advances from unconsolidated affiliates	85		31		28
Proceeds from sales of noncontrolling interests, net	—		1,219		1,732
Distributions to noncontrolling interests	(297)		(730)		(237)
Contributions from noncontrolling interests	1,235		1,570		31
Termination of interest rate and settlement of cross-currency swaps	46		(99)		—
Other	(56)		(85)		(35)
Net cash provided by financing activities	5,424		2,419		3,779
Effect of exchange rate changes on cash, cash equivalents and restricted cash	(13)		6		(1)
Increase (decrease) in cash, cash equivalents and restricted cash	1,200		(73)		(119)
Cash, cash equivalents and restricted cash, January 1	389		462		581
Cash, cash equivalents and restricted cash, December 31	$	1,589	$	389	$	462
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	1,205	$	1,172	$	1,014
Income tax payments, net of refunds	289		197		284
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued interest receivable capitalized to note receivable	$	17	$	16	$	16
Repayments of advances from unconsolidated affiliate in lieu of distributions	62		36		32
Accrued capital expenditures for PP&E	1,181		1,052		590
Capital expenditures reclassed from assets to PP&E	53		18		5
Increase in ARO capitalized to PP&E	1		33		91
Increase in finance lease obligations capitalized to PP&E	41		57		57
Amortized debt issuance costs capitalized to PP&E	13		4		—
Unamortized debt issuance costs reclassed from assets to debt	27		9		—
Accrued interest payable capitalized to due to unconsolidated affiliate	16		—		—
Preferred dividends declared but not paid	11		11		11
Common dividends declared but not paid	393		376		360
Common dividends issued in stock	54		—		—
Net exercise of stock options	9		—		—
Contributions from NCI	—		200		—

See Notes to Consolidated Financial Statements.

2024 Form 10-K | F-13

SEMPRA
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Dollars in millions)
	Years ended December 31, 2024, 2023 and 2022
	Preferred stock		Common stock		Retained earnings		Accumulated other comprehensive income (loss)		Sempra shareholders' equity		Non- controlling interests		Total equity
Balance at December 31, 2021	$	889	$	11,862	$	13,548	$	(318)	$	25,981	$	1,438	$	27,419
Net income					2,139				2,139		146		2,285
Other comprehensive income							174		174		54		228
Share-based compensation expense			71						71				71
Dividends declared:
Series C preferred stock ($48.75/share)					(44)				(44)				(44)
Common stock ($2.29/share)					(1,441)				(1,441)				(1,441)
Preferred dividends of subsidiary					(1)				(1)				(1)
Issuances of common stock			4						4				4
Repurchases of common stock			(478)						(478)				(478)
Noncontrolling interest activities:
Contributions											31		31
Distributions											(237)		(237)
Sale			701				9		710		709		1,419
Balance at December 31, 2022	889		12,160		14,201		(135)		27,115		2,141		29,256
Net income					3,075				3,075		543		3,618
Other comprehensive income (loss)							31		31		(28)		3
Share-based compensation expense			80						80				80
Dividends declared:
Series C preferred stock ($48.75/share)					(44)				(44)				(44)
Common stock ($2.38/share)					(1,499)				(1,499)				(1,499)
Preferred dividends of subsidiary					(1)				(1)				(1)
Issuances of common stock			144						144				144
Repurchases of common stock			(32)						(32)				(32)
Noncontrolling interest activities:
Contributions			(145)						(145)		1,770		1,625
Distributions											(730)		(730)
Sales			(3)				(46)		(49)		1,283		1,234
Balance at December 31, 2023	889		12,204		15,732		(150)		28,675		4,979		33,654
Net income					2,862				2,862		638		3,500
Other comprehensive (loss) income							(16)		(16)		11		(5)
Share-based compensation expense			86						86				86
Dividends declared:
Series C preferred stock ($48.75/share)					(44)				(44)				(44)
Common stock ($2.48/share)					(1,570)				(1,570)				(1,570)
Preferred dividends of subsidiary					(1)				(1)				(1)
Issuances of common stock			1,273						1,273				1,273
Repurchases of common stock			(43)						(43)				(43)
Noncontrolling interest activities:
Contributions											1,235		1,235
Distributions											(297)		(297)
Balance at December 31, 2024	$	889	$	13,520	$	16,979	$	(166)	$	31,222	$	6,566	$	37,788

See Notes to Consolidated Financial Statements.

2024 Form 10-K | F-14

SAN DIEGO GAS & ELECTRIC COMPANY
STATEMENTS OF OPERATIONS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Operating revenues:
Electric	$	4,313	$	4,349	$	4,795
Natural gas	1,028		1,248		1,043
Total operating revenues	5,341		5,597		5,838
Operating expenses:
Cost of electric fuel and purchased power	308		445		994
Cost of natural gas	242		532		363
Operation and maintenance	1,692		1,846		1,677
Depreciation and amortization	1,223		1,098		982
Franchise fees and other taxes	402		381		373
Total operating expenses	3,867		4,302		4,389
Operating income	1,474		1,295		1,449
Other income, net	90		97		92
Interest income	5		15		5
Interest expense	(525)		(497)		(449)
Income before income taxes	1,044		910		1,097
Income tax (expense) benefit	(153)		26		(182)
Net income/Earnings attributable to common shares	$	891	$	936	$	915

See Notes to Financial Statements.

2024 Form 10-K | F-15

SAN DIEGO GAS & ELECTRIC COMPANY
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Years ended December 31, 2024, 2023 and 2022
	Pretax amount		Income tax (expense) benefit		Net-of-tax amount
2024:
Net income	$	1,044	$	(153)	$	891
Other comprehensive income (loss):
Pension and other postretirement benefits	(3)		(1)		(4)
Total other comprehensive loss	(3)		(1)		(4)
Comprehensive income	$	1,041	$	(154)	$	887
2023:
Net income	$	910	$	26	$	936
Other comprehensive income (loss):
Pension and other postretirement benefits	(2)		1		(1)
Total other comprehensive loss	(2)		1		(1)
Comprehensive income	$	908	$	27	$	935
2022:
Net income	$	1,097	$	(182)	$	915
Other comprehensive income (loss):
Pension and other postretirement benefits	4		(1)		3
Total other comprehensive income	4		(1)		3
Comprehensive income	$	1,101	$	(183)	$	918

See Notes to Financial Statements.

2024 Form 10-K | F-16

SAN DIEGO GAS & ELECTRIC COMPANY
BALANCE SHEETS
(Dollars in millions)
	December 31,
	2024		2023
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	50
Accounts receivable – trade, net	774		870
Accounts receivable – other, net	89		141
Income taxes receivable, net	27		236
Inventories	202		153
Prepaid expenses	139		165
Regulatory assets	16		19
Greenhouse gas allowances	27		158
Other current assets	27		31
Total current assets	1,301		1,823
Other assets:
Regulatory assets	2,024		1,968
Greenhouse gas allowances	272		202
Nuclear decommissioning trusts	875		872
Right-of-use assets – operating leases	795		368
Wildfire fund	262		269
Other long-term assets	133		134
Total other assets	4,361		3,813
Property, plant and equipment:
Property, plant and equipment	33,162		30,918
Less accumulated depreciation and amortization	(8,051)		(7,369)
Property, plant and equipment, net	25,111		23,549
Total assets	$	30,773	$	29,185

See Notes to Financial Statements.

2024 Form 10-K | F-17

SAN DIEGO GAS & ELECTRIC COMPANY
BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	December 31,
	2024		2023
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities:
Short-term debt	$	417	$	—
Accounts payable	742		808
Due to unconsolidated affiliates	59		73
Interest payable	84		81
Accrued compensation and benefits	175		145
Accrued franchise fees	54		112
Regulatory liabilities	75		447
Current portion of long-term debt and finance leases	42		441
Greenhouse gas obligations	27		158
Asset retirement obligations	97		116
Other current liabilities	215		216
Total current liabilities	1,987		2,597
Long-term debt and finance leases	10,018		9,453
Deferred credits and other liabilities:
Regulatory liabilities	2,701		2,534
Greenhouse gas obligations	62		—
Pension obligation, net of plan assets	28		79
Deferred income taxes	3,211		2,873
Asset retirement obligations	803		778
Deferred credits and other	1,399		969
Total deferred credits and other liabilities	8,204		7,233
Commitments and contingencies (Note 15)
Shareholder’s equity:
Preferred stock (45,000,000 shares authorized; none issued)	—		—
Common stock (255,000,000 shares authorized; 116,583,358 shares outstanding; no par value)	1,660		1,660
Retained earnings	8,916		8,250
Accumulated other comprehensive income (loss)	(12)		(8)
Total shareholder’s equity	10,564		9,902
Total liabilities and shareholder’s equity	$	30,773	$	29,185

See Notes to Financial Statements.

2024 Form 10-K | F-18

SAN DIEGO GAS & ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	891	$	936	$	915
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	1,223		1,098		982
Deferred income taxes and investment tax credits	169		135		93
Bad debt expense	55		112		46
Other	(14)		(35)		(34)
Net change in working capital components:
Accounts receivable	92		(213)		(163)
Due to/from unconsolidated affiliates, net	(14)		(62)		38
Income taxes receivable/payable, net	209		(236)		9
Inventories	(49)		(19)		(11)
Other current assets	(21)		(17)		(80)
Accounts payable	(32)		31		153
Regulatory balancing accounts, net	(429)		571		(10)
Other current liabilities	(21)		129		62
Changes in noncurrent assets and liabilities, net	14		(494)		(271)
Net cash provided by operating activities	2,073		1,936		1,729
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(2,522)		(2,540)		(2,473)
Purchases of nuclear decommissioning trust assets	(826)		(532)		(586)
Proceeds from sales of nuclear decommissioning trust assets	874		592		639
Other	13		8		8
Net cash used in investing activities	(2,461)		(2,472)		(2,412)
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid	(225)		(100)		(100)
Issuances of debt (maturities greater than 90 days)	594		1,389		1,395
Payments on debt (maturities greater than 90 days) and finance leases	(442)		(490)		(425)
Increase (decrease) in short-term debt, net	417		(205)		(196)
Debt issuance costs	(6)		(13)		(9)
Other	—		(2)		—
Net cash provided by financing activities	338		579		665
(Decrease) increase in cash and cash equivalents	(50)		43		(18)
Cash and cash equivalents, January 1	50		7		25
Cash and cash equivalents, December 31	$	—	$	50	$	7
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	514	$	472	$	431
Income tax (refunds) payments, net	(225)		76		79
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued capital expenditures for PP&E	$	230	$	264	$	231
Increase in finance lease obligations capitalized to PP&E	14		17		16
Increase in ARO capitalized to PP&E	24		29		15

See Notes to Financial Statements.

2024 Form 10-K | F-19

SAN DIEGO GAS & ELECTRIC COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY
(Dollars in millions)
	Years ended December 31, 2024, 2023 and 2022
	Common stock		Retained earnings		Accumulated other comprehensive income (loss)		Total shareholder's equity
Balance at December 31, 2021	$	1,660	$	6,599	$	(10)	$	8,249
Net income			915				915
Other comprehensive income					3		3
Common stock dividends declared ($0.86/share)			(100)				(100)
Balance at December 31, 2022	1,660		7,414		(7)		9,067
Net income			936				936
Other comprehensive loss					(1)		(1)
Common stock dividends declared ($0.86/share)			(100)				(100)
Balance at December 31, 2023	1,660		8,250		(8)		9,902
Net income			891				891
Other comprehensive loss					(4)		(4)
Common stock dividends declared ($1.93/share)			(225)				(225)
Balance at December 31, 2024	$	1,660	$	8,916	$	(12)	$	10,564

See Notes to Financial Statements.

2024 Form 10-K | F-20

SOUTHERN CALIFORNIA GAS COMPANY
STATEMENTS OF OPERATIONS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Operating revenues	$	6,209	$	8,289	$	6,840
Operating expenses:
Cost of natural gas	959		3,264		2,233
Operation and maintenance	2,791		2,821		2,402
Aliso Canyon litigation and regulatory matters	—		—		259
Depreciation and amortization	910		839		761
Franchise fees and other taxes	273		278		247
Total operating expenses	4,933		7,202		5,902
Operating income	1,276		1,087		938
Other income (expense), net	25		(4)		(8)
Interest income	9		9		6
Interest expense	(323)		(285)		(198)
Income before income taxes	987		807		738
Income tax (expense) benefit	(31)		5		(138)
Net income	956		812		600
Preferred dividends	(1)		(1)		(1)
Earnings attributable to common shares	$	955	$	811	$	599

See Notes to Financial Statements.

2024 Form 10-K | F-21

SOUTHERN CALIFORNIA GAS COMPANY
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Years ended December 31, 2024, 2023 and 2022
	Pretax amount		Income tax (expense) benefit		Net-of-tax amount
2024:
Net income	$	987	$	(31)	$	956
Other comprehensive income (loss):
Financial instruments	1		—		1
Pension and other postretirement benefits	(4)		(1)		(5)
Total other comprehensive loss	(3)		(1)		(4)
Comprehensive income	$	984	$	(32)	$	952
2023:
Net income	$	807	$	5	$	812
Other comprehensive income (loss):
Financial instruments	1		—		1
Total other comprehensive income	1		—		1
Comprehensive income	$	808	$	5	$	813
2022:
Net income	$	738	$	(138)	$	600
Other comprehensive income (loss):
Financial instruments	1		—		1
Pension and other postretirement benefits	8		(2)		6
Total other comprehensive income	9		(2)		7
Comprehensive income	$	747	$	(140)	$	607

See Notes to Financial Statements.

2024 Form 10-K | F-22

SOUTHERN CALIFORNIA GAS COMPANY
BALANCE SHEETS
(Dollars in millions)
	December 31,
	2024		2023
ASSETS
Current assets:
Cash and cash equivalents	$	12	$	2
Accounts receivable – trade, net	932		985
Accounts receivable – other, net	71		102
Due from unconsolidated affiliates	16		22
Inventories	287		277
Regulatory assets	42		204
Greenhouse gas allowances	176		950
Other current assets	71		100
Total current assets	1,607		2,642
Other assets:
Regulatory assets	1,844		1,715
Greenhouse gas allowances	526		62
Right-of-use assets – operating leases	18		29
Other long-term assets	609		645
Total other assets	2,997		2,451
Property, plant and equipment:
Property, plant and equipment	29,084		27,025
Less accumulated depreciation and amortization	(8,330)		(7,852)
Property, plant and equipment, net	20,754		19,173
Total assets	$	25,358	$	24,266

See Notes to Financial Statements.

2024 Form 10-K | F-23

SOUTHERN CALIFORNIA GAS COMPANY
BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	December 31,
	2024		2023
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term debt	$	1,037	$	946
Accounts payable – trade	752		811
Accounts payable – other	158		184
Due to unconsolidated affiliates	38		38
Accrued compensation and benefits	245		213
Regulatory liabilities	64		103
Current portion of long-term debt and finance leases	373		523
Greenhouse gas obligations	176		950
Asset retirement obligations	91		73
Other current liabilities	451		566
Total current liabilities	3,385		4,407
Long-term debt and finance leases	7,031		6,288
Deferred credits and other liabilities:
Regulatory liabilities	1,115		1,202
Greenhouse gas obligations	410		—
Pension obligation, net of plan assets	45		231
Deferred income taxes	2,005		1,586
Asset retirement obligations	2,839		2,774
Deferred credits and other	367		368
Total deferred credits and other liabilities	6,781		6,161
Commitments and contingencies (Note 15)
Shareholders’ equity:
Preferred stock (11,000,000 shares authorized; 862,043 shares outstanding)	22		22
Common stock (100,000,000 shares authorized; 91,300,000 shares outstanding; no par value)	2,316		2,316
Retained earnings	5,850		5,095
Accumulated other comprehensive income (loss)	(27)		(23)
Total shareholders’ equity	8,161		7,410
Total liabilities and shareholders’ equity	$	25,358	$	24,266

See Notes to Financial Statements.

2024 Form 10-K | F-24

SOUTHERN CALIFORNIA GAS COMPANY
STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	956	$	812	$	600
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	910		839		761
Deferred income taxes and investment tax credits	28		12		146
Bad debt expense	97		294		70
Other	(6)		(12)		(12)
Net change in working capital components:
Accounts receivable	(13)		207		(512)
Due to/from unconsolidated affiliates, net	6		57		(28)
Income taxes receivable/payable, net	13		(8)		23
Inventories	(10)		(118)		13
Other current assets	6		(1,053)		(139)
Accounts payable	(103)		(179)		191
Regulatory balancing accounts, net	(27)		(311)		46
Reserve for Aliso Canyon costs	(12)		(98)		(1,851)
Other current liabilities	46		1,047		185
Insurance receivable for Aliso Canyon costs	—		—		360
Changes in other noncurrent assets and liabilities, net	(100)		(100)		(307)
Net cash provided by (used in) operating activities	1,791		1,389		(454)
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(2,231)		(2,020)		(1,993)
Net cash used in investing activities	(2,231)		(2,020)		(1,993)
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid	(200)		(100)		—
Preferred dividends paid	(1)		(1)		(1)
Equity contribution from Sempra	—		—		650
Issuances of debt (maturities greater than 90 days)	1,794		997		2,094
Payments on debt (maturities greater than 90 days) and finance leases	(524)		(1,120)		(15)
(Decrease) increase in short-term debt, net	(609)		846		(285)
Debt issuance costs	(10)		(10)		(12)
Net cash provided by financing activities	450		612		2,431
Increase (decrease) in cash and cash equivalents	10		(19)		(16)
Cash and cash equivalents, January 1	2		21		37
Cash and cash equivalents, December 31	$	12	$	2	$	21
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	299	$	279	$	173
Income tax (refunds) payments, net	(9)		6		(31)
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued capital expenditures for PP&E	$	308	$	290	$	245
Capital expenditures reclassed from assets to PP&E	50		—		—
Increase in finance lease obligations capitalized to PP&E	27		40		41
(Decrease) increase in ARO capitalized to PP&E	(23)		1		63

See Notes to Financial Statements.

2024 Form 10-K | F-25

SOUTHERN CALIFORNIA GAS COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Dollars in millions)
	Years ended December 31, 2024, 2023 and 2022
	Preferred stock		Common stock		Retained earnings		Accumulated other comprehensive income (loss)		Total shareholders’ equity
Balance at December 31, 2021	$	22	$	1,666	$	3,785	$	(31)	$	5,442
Net income					600				600
Other comprehensive income							7		7
Dividends declared:
Preferred stock ($1.50/share)					(1)				(1)
Equity contributions from Sempra			650						650
Balance at December 31, 2022	22		2,316		4,384		(24)		6,698
Net income					812				812
Other comprehensive income							1		1
Dividends declared:
Preferred stock ($1.50/share)					(1)				(1)
Common stock ($1.10/share)					(100)				(100)
Balance at December 31, 2023	22		2,316		5,095		(23)		7,410
Net income					956				956
Other comprehensive loss							(4)		(4)
Dividends declared:
Preferred stock ($1.50/share)					(1)				(1)
Common stock ($2.19/share)					(200)				(200)
Balance at December 31, 2024	$	22	$	2,316	$	5,850	$	(27)	$	8,161

See Notes to Financial Statements.

2024 Form 10-K | F-26

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA

PRINCIPLES OF CONSOLIDATION

Sempra

Sempra’s Consolidated Financial Statements include the accounts of Sempra, a California-based holding company, and its consolidated entities, which invest in, develop and operate energy infrastructure in North America, and provide electric and gas services to customers. Sempra has three operating and reportable segments, which we describe in Note 16. All references in these Notes to our reportable segments are not intended to refer to any legal entity with the same or similar name.

SDG&E

SDG&E’s common stock is wholly owned by Enova Corporation, which is a wholly owned subsidiary of Sempra. SDG&E is a regulated public utility that provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County. SDG&E has one operating and reportable segment.

SoCalGas

SoCalGas’ common stock is wholly owned by Pacific Enterprises, which is a wholly owned subsidiary of Sempra. SoCalGas is a regulated public natural gas distribution utility, serving customers throughout most of Southern California and part of central California. SoCalGas has one operating and reportable segment.

BASIS OF PRESENTATION

This is a combined report of Sempra, SDG&E and SoCalGas. We provide separate information for SDG&E and SoCalGas as required. We have eliminated intercompany accounts and transactions within Sempra’s consolidated financial statements.

Use of Estimates in the Preparation of the Financial Statements

We have prepared our financial statements in conformity with U.S. GAAP. This requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes, including the disclosure of contingent assets and liabilities at the date of the financial statements. Although we believe the estimates and assumptions are reasonable, actual amounts ultimately may differ significantly from those estimates.

Subsequent Events

We evaluated events and transactions that occurred after December 31, 2024 through the date the financial statements were issued, and in the opinion of management, the accompanying financial statements reflect all adjustments and disclosures necessary for a fair presentation.

REGULATED OPERATIONS

SDG&E’s and SoCalGas’ accounting policies and financial statements reflect the application of U.S. GAAP provisions governing rate-regulated operations and the policies of the CPUC and the FERC. Under these provisions, a regulated utility records regulatory assets, which are generally costs that would otherwise be charged to expense, if it is probable that, through the ratemaking process, the utility will recover those assets from customers. To the extent that recovery is no longer probable, the related regulatory assets are written off. Regulatory liabilities generally represent amounts collected from customers in advance of the actual expenditure by the utility. If the actual expenditures are less than amounts previously collected from customers, the excess would be refunded to customers, generally by reducing future rates. Regulatory assets and liabilities may also arise from other transactions such as unrealized losses and/or gains on fixed-price contracts and other derivatives or certain deferred income tax benefits that are passed through to customers in future rates. In addition, SDG&E and SoCalGas record regulatory liabilities when the CPUC or, in the case of SDG&E, the FERC, requires a refund to be made to customers or has required that a gain or other transaction of net allowable costs be given to customers over future periods.

2024 Form 10-K | F-27

Determining probability of recovery of regulatory assets requires judgment by management and may include, but is not limited to, consideration of:

▪the nature of the event giving rise to the assessment

▪existing statutes and regulatory code

▪legal precedents

▪regulatory principles and analogous regulatory actions

▪testimony presented in regulatory hearings

▪regulatory orders

▪a commission-authorized mechanism established for the accumulation of costs

▪status of applications for rehearings or state court appeals

▪specific approval from a commission

▪historical experience

Our Sempra Texas Utilities segment is comprised of our equity method investments in Oncor Holdings, which owns an 80.25% interest in Oncor, and Sharyland Holdings, which owns 100% of Sharyland Utilities. Oncor and Sharyland Utilities are regulated electric transmission and distribution utilities in Texas and their rates are regulated by the PUCT and, in the case of Oncor, certain cities and are subject to regulatory rate-setting processes and earnings oversight. Oncor and Sharyland Utilities prepare their financial statements in accordance with the provisions of U.S. GAAP governing rate-regulated operations.

Sempra Infrastructure’s natural gas distribution utility, Ecogas, also applies U.S. GAAP provisions governing rate-regulated operations, including the same evaluation of probability of recovery of regulatory assets described above. Certain business activities at Sempra Infrastructure are regulated by the CRE and the FERC and meet the regulatory accounting requirements of U.S. GAAP.

FAIR VALUE MEASUREMENTS

We measure certain assets and liabilities at fair value on a recurring basis, primarily NDT and benefit plan trust assets and derivatives. We also measure certain assets at fair value on a non-recurring basis in certain circumstances.

A fair value measurement reflects the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model. Also, we consider an issuer’s credit standing when measuring its liabilities at fair value.

We establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 – Pricing inputs are unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 financial instruments primarily consist of listed equities, short-term investments, and U.S. government treasury securities, primarily in the NDT and benefit plan trusts, and exchange-traded derivatives.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including:

▪quoted forward prices for commodities

▪time value

▪current market and contractual prices for the underlying instruments

▪volatility factors

▪other relevant economic measures

2024 Form 10-K | F-28

Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our financial instruments in this category include listed equities, domestic corporate bonds, municipal bonds and other foreign bonds, primarily in the NDT and benefit plan trusts, and non-exchange-traded derivatives such as interest rate instruments and over-the-counter forwards and options.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value from the perspective of a market participant. Our Level 3 financial instruments consist of CRRs and, until December 31, 2022, fixed-price electricity positions, at SDG&E and the Support Agreement at Sempra Infrastructure.

VARIABLE INTEREST ENTITIES

We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based on qualitative and quantitative analyses, which assess:

▪the purpose and design of the VIE;

▪the nature of the VIE’s risks and the risks we absorb;

▪the power to direct activities that most significantly impact the economic performance of the VIE; and

▪the obligation to absorb losses or the right to receive benefits that could be significant to the VIE.

We will continue to evaluate our VIEs for any changes that may impact our determination of whether an entity is a VIE and if we are the primary beneficiary.

SDG&E

SDG&E’s power procurement is subject to reliability requirements that may require SDG&E to enter into various PPAs that include variable interests. SDG&E evaluates the respective entities to determine if variable interests exist and, based on the qualitative and quantitative analyses described above, if SDG&E, and indirectly Sempra, is the primary beneficiary.

SDG&E has agreements under which it purchases power generated by facilities for which it supplies all of the natural gas to fuel the power plant (i.e., tolling agreements). SDG&E’s obligation to absorb natural gas costs may be a significant variable interest. In addition, SDG&E has the power to direct the dispatch of electricity generated by these facilities. Based on our analysis, the ability to direct the dispatch of electricity may have the most significant impact on the economic performance of the entity owning the generating facility because of the associated exposure to the cost of natural gas, which fuels the plants, and the value of electricity produced. To the extent that SDG&E (1) is obligated to purchase and provide fuel to operate the facility, (2) has the power to direct the dispatch, and (3) purchases all of the output from the facility for a substantial portion of the facility’s useful life, SDG&E may be the primary beneficiary of the entity owning the generating facility. SDG&E determines if it is the primary beneficiary in these cases based on a qualitative approach in which it considers the operational characteristics of the facility, including its expected power generation output relative to its capacity to generate and the financial structure of the entity, among other factors. If SDG&E determines that it is the primary beneficiary, SDG&E and Sempra consolidate the entity that owns the facility as a VIE.

In addition to tolling agreements, other variable interests involve various elements of fuel and power costs, and other components of cash flows expected to be paid to or received by our counterparties. In most of these cases, the expectation of variability is not substantial, and SDG&E generally does not have the power to direct activities, including the operation and maintenance activities of the generating facility, that most significantly impact the economic performance of the other VIEs. If our ongoing evaluation of these VIEs were to conclude that SDG&E becomes the primary beneficiary and consolidation by SDG&E becomes necessary, the effects could be significant to the financial position and liquidity of SDG&E and Sempra.

SDG&E determined that none of its PPAs and tolling agreements resulted in SDG&E being the primary beneficiary of a VIE at December 31, 2024 and 2023. PPAs and tolling agreements that relate to SDG&E’s involvement with VIEs are primarily accounted for as finance leases. The carrying amounts of the assets and liabilities under these contracts are included in PP&E, net, and finance lease liabilities with balances of $1,138 million and $1,166 million at December 31, 2024 and 2023, respectively. SDG&E recovers costs incurred on PPAs, tolling agreements and other variable interests through CPUC-approved long-term power procurement plans. SDG&E has no residual interest in the respective entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 15. As a result, SDG&E’s potential exposure to loss from its variable interest in these VIEs is not significant.

2024 Form 10-K | F-29

Other Sempra

Oncor Holdings

Oncor Holdings is a VIE. Sempra is not the primary beneficiary of this VIE because of the structural and operational ring-fencing and governance measures in place that prevent us from having the power to direct the significant activities of Oncor Holdings. As a result, we do not consolidate Oncor Holdings and instead account for our ownership interest as an equity method investment. See Note 5 for additional information about our equity method investment in Oncor Holdings and restrictions on our ability to influence its activities. Our maximum exposure to loss, which fluctuates over time, from our interest in Oncor Holdings does not exceed the carrying value of our investment, which was $15,400 million and $14,266 million at December 31, 2024 and 2023, respectively.

Cameron LNG JV

Cameron LNG JV is a VIE principally due to contractual provisions that transfer certain risks to customers. Sempra is not the primary beneficiary of this VIE because we do not have the power to direct the most significant activities of Cameron LNG JV, including LNG production and operation and maintenance activities at the liquefaction facility. Therefore, we account for our investment in Cameron LNG JV under the equity method. The carrying value of our investment was $1,149 million and $1,008 million at December 31, 2024 and 2023, respectively. Our maximum exposure to loss, which fluctuates over time, includes the carrying value of our investment and our obligation under the SDSRA, which we discuss in Note 5.

CFIN

As we discuss in Note 5, in July 2020, Sempra entered into a Support Agreement for the benefit of CFIN, which is a VIE. Sempra is not the primary beneficiary of this VIE because we do not have the power to direct the most significant activities of CFIN, including modification, prepayment, and refinance decisions related to the financing arrangement with external lenders and Cameron LNG JV’s four project owners as well as the ability to determine and enforce remedies in the event of default. The conditional obligations of the Support Agreement represent a variable interest that we measure at fair value on a recurring basis (see Note 10). Sempra’s maximum exposure to loss under the terms of the Support Agreement is $979 million.

ECA LNG Phase 1

ECA LNG Phase 1 is a VIE because its total equity at risk is not sufficient to finance its activities without additional subordinated financial support. We expect that ECA LNG Phase 1 will require future capital contributions or other financial support to finance the construction of the facility. Sempra is the primary beneficiary of this VIE because we have the power to direct the activities related to the construction and future operation and maintenance of the liquefaction facility. As a result, we consolidate ECA LNG Phase 1. Sempra consolidated $1,758 million and $1,580 million of assets at December 31, 2024 and 2023, respectively, consisting primarily of PP&E, net, attributable to ECA LNG Phase 1 that could be used only to settle obligations of this VIE and that are not available to settle obligations of Sempra, and $1,080 million and $1,029 million of liabilities at December 31, 2024 and 2023, respectively, consisting primarily of long-term debt attributable to ECA LNG Phase 1 for which creditors do not have recourse to the general credit of Sempra. Additionally, as we discuss in Note 6, IEnova and TotalEnergies SE have provided guarantees for 83.4% and 16.6%, respectively, of the loan facility supporting construction of the liquefaction facility.

Port Arthur LNG

Port Arthur LNG is a VIE because its total equity at risk is not sufficient to finance its activities without additional subordinated financial support. We expect that Port Arthur LNG will require future capital contributions or other financial support to finance the construction of the PA LNG Phase 1 project. Sempra is the primary beneficiary of this VIE because we have the power to direct the activities related to the construction and future operation and maintenance of the liquefaction facility. As a result, we consolidate Port Arthur LNG. Sempra consolidated $6,419 million and $3,927 million of assets at December 31, 2024 and 2023, respectively, consisting primarily of PP&E, net, attributable to Port Arthur LNG that could be used only to settle obligations of this VIE and that are not available to settle obligations of Sempra, and $1,584 million and $600 million of liabilities at December 31, 2024 and 2023, respectively, consisting primarily of long-term debt and accounts payable attributable to Port Arthur LNG for which creditors do not have recourse to the general credit of Sempra.

2024 Form 10-K | F-30

CASH, CASH EQUIVALENTS AND RESTRICTED CASH

Cash equivalents are highly liquid investments with original maturities of three months or less at the date of purchase.

Restricted cash includes:

▪certain funds at Port Arthur LNG for which withdrawals and usage are dictated by its debt agreements

▪funds held as collateral in lieu of a customer’s letters of credit associated with its LNG storage and regasification agreement

▪funds denominated in U.S. dollars and Mexican pesos to pay for rights-of-way and other costs pursuant to trust agreements related to pipeline projects

▪funds held in a delisting trust for the purpose of purchasing the remaining publicly owned IEnova shares

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on Sempra’s Consolidated Balance Sheets to the sum of such amounts reported on Sempra’s Consolidated Statements of Cash Flows.

RECONCILIATION OF CASH, CASH EQUIVALENTS AND RESTRICTED CASH
(Dollars in millions)
	December 31,
	2024		2023
Sempra:
Cash and cash equivalents	$	1,565	$	236
Restricted cash, current	21		49
Restricted cash, noncurrent	3		104
Total cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows	$	1,589	$	389

CREDIT LOSSES

We are exposed to credit losses from financial assets measured at amortized cost, including trade and other accounts receivable, amounts due from unconsolidated affiliates, our net investment in sales-type leases and a note receivable. We are also exposed to credit losses from off-balance sheet arrangements through Sempra’s guarantee related to Cameron LNG JV’s SDSRA, which we discuss in Note 5.

We regularly monitor and evaluate credit losses and record allowances for expected credit losses, if necessary, for trade and other accounts receivable using a combination of factors, including past-due status based on contractual terms, trends in write-offs, the age of the receivables and customer payment patterns, historical and industry trends, counterparty creditworthiness, economic conditions and specific events, such as bankruptcies, pandemics and other factors. We write off financial assets measured at amortized cost in the period in which we determine they are not recoverable. We record recoveries of amounts previously written off when it is known that they will be recovered.

After considering the past-due status of receivables, payment history and other customer-specific information, in 2024 and 2023, Sempra recorded a provision for expected credit losses of $53 million and $52 million, respectively, on a customer’s past due account balance.

The implementation of customer assistance programs and higher 2023 winter season customer billings have resulted in certain SDG&E and SoCalGas customers exhibiting slower payment and higher levels of nonpayment than has been the case historically.

SDG&E and SoCalGas have regulatory mechanisms to recover credit losses and thus record changes in the allowances for credit losses related to Accounts Receivable – Trade that are probable of recovery in regulatory accounts. We discuss regulatory accounts in Note 4.

2024 Form 10-K | F-31

Changes in allowances for credit losses for trade receivables and other receivables are as follows:

CHANGES IN ALLOWANCES FOR CREDIT LOSSES
(Dollars in millions)
	2024		2023		2022
Sempra:
Allowances for credit losses at January 1	$	533	$	181	$	136
Provisions for expected credit losses	203		468		123
Write-offs	(222)		(116)		(78)
Allowances for credit losses at December 31	$	514	$	533	$	181
SDG&E:
Allowances for credit losses at January 1	$	144	$	78	$	66
Provisions for expected credit losses	52		115		54
Write-offs	(82)		(49)		(42)
Allowances for credit losses at December 31	$	114	$	144	$	78
SoCalGas:
Allowances for credit losses at January 1	$	331	$	98	$	69
Provisions for expected credit losses	94		300		65
Write-offs	(140)		(67)		(36)
Allowances for credit losses at December 31	$	285	$	331	$	98

Allowances for credit losses related to trade receivables and other receivables are included in the Consolidated Balance Sheets as follows:

ALLOWANCES FOR CREDIT LOSSES
(Dollars in millions)
	December 31,
	2024		2023
Sempra:
Accounts receivable – trade, net	$	447	$	480
Accounts receivable – other, net	53		52
Other long-term assets	14		1
Total allowances for credit losses	$	514	$	533
SDG&E:
Accounts receivable – trade, net	$	81	$	116
Accounts receivable – other, net	25		27
Other long-term assets	8		1
Total allowances for credit losses	$	114	$	144
SoCalGas:
Accounts receivable – trade, net	$	251	$	306
Accounts receivable – other, net	28		25
Other long-term assets	6		—
Total allowances for credit losses	$	285	$	331

As we discuss below in “Note Receivable,” we have an interest-bearing promissory note due from KKR Pinnacle. On a quarterly basis, we evaluate credit losses and record allowances for expected credit losses on this note receivable, including compounded interest and unamortized transaction costs, based on published default rate studies, the maturity date of the instrument and an internally developed credit rating. At December 31, 2024 and 2023, $5 million and $6 million, respectively, of expected credit losses are included in Other Long-Term Assets on Sempra’s Consolidated Balance Sheets.

As we discuss in Note 5, Sempra provided a guarantee for the benefit of Cameron LNG JV related to amounts withdrawn by Sempra Infrastructure from the SDSRA. On a quarterly basis, we evaluate credit losses and record liabilities for expected credit losses on this off-balance sheet arrangement based on external credit ratings, published default rate studies and the maturity date of the arrangement. At both December 31, 2024 and 2023, $5 million of expected credit losses are included in Deferred Credits and Other on Sempra’s Consolidated Balance Sheets.

2024 Form 10-K | F-32

CONCENTRATION OF CREDIT RISK

Credit risk is the risk of loss that would be incurred as a result of nonperformance by our counterparties on their contractual obligations. We have policies governing the management of credit risk that are administered by the respective credit departments at each of the Registrants and overseen by their separate risk management committees.

This oversight includes calculating current and potential credit risk on a regular basis and monitoring actual balances in comparison to approved limits. We establish credit limits based on risk and return considerations under terms customarily available in the industry. We avoid concentration of counterparties whenever possible, and we believe our credit policies significantly reduce overall credit risk. These policies include an evaluation of:

▪prospective counterparties’ financial condition (including credit ratings)

▪collateral requirements

▪the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty

▪downgrade triggers

We believe that we have provided adequate reserves for counterparty nonperformance in our allowances for credit losses.

2024 Form 10-K | F-33

TRANSACTIONS WITH AFFILIATES

We summarize amounts due from and to unconsolidated affiliates at the Registrants in the following table.

AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	December 31,
	2024		2023
Sempra:
Tax sharing agreement with Oncor Holdings	$	8	$	25
Various affiliates	5		6
Total due from unconsolidated affiliates – current	$	13	$	31
TAG Pipelines – 5.5% Note due January 9, 2024(1)	$	—	$	(5)
Total due to unconsolidated affiliates – current	$	—	$	(5)
TAG Pipelines(1):
5.5% Note due January 14, 2025	$	—	$	(24)
5.5% Note due July 16, 2025	—		(23)
5.5% Note due January 14, 2026	(8)		(20)
5.5% Note due July 14, 2026	(12)		(11)
5.5% Note due January 19, 2027	(15)		(14)
5.5% Note due July 21, 2027	(19)		(17)
5.5% Note due January 19, 2028	(48)		—
5.5% Note due July 18, 2028	(41)		—
TAG Norte – 5.74% Note due December 17, 2029(1)	(209)		(198)
Total due to unconsolidated affiliates – noncurrent	$	(352)	$	(307)
SDG&E:
Sempra	$	(42)	$	(44)
SoCalGas	(14)		(21)
Various affiliates	(3)		(8)
Total due to unconsolidated affiliates – current	$	(59)	$	(73)
Income taxes due from Sempra(2)	$	38	$	246
SoCalGas:
SDG&E	$	14	$	21
Various affiliates	2		1
Total due from unconsolidated affiliates – current	$	16	$	22
Sempra	$	(38)	$	(38)
Total due to unconsolidated affiliates – current	$	(38)	$	(38)
Income taxes due (to) from Sempra(2)	$	(6)	$	6

(1)    U.S. dollar-denominated loans at fixed interest rates. Amounts include principal balances plus accumulated interest outstanding and VAT payable to the Mexican government.

(2)    SDG&E and SoCalGas are included in the consolidated income tax return of Sempra, and their respective income tax expense is computed as an amount equal to that which would result from each company having always filed a separate return. Amounts include current and noncurrent income taxes due to/from Sempra.

2024 Form 10-K | F-34

The following table summarizes income statement information from unconsolidated affiliates.

INCOME STATEMENT IMPACT FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra:
Revenues	$	40	$	44	$	41
Interest income	—		—		16
Interest expense	16		15		15
SDG&E:
Revenues	$	23	$	21	$	16
Cost of sales	146		113		92
SoCalGas:
Revenues	$	169	$	124	$	100
Cost of sales(1)	(5)		35		(9)

(1)    Includes net commodity costs from natural gas transactions with unconsolidated affiliates.

Sempra, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Also, from time-to-time, SDG&E and SoCalGas may make short-term advances of surplus cash to Sempra at interest rates based on the federal funds effective rate plus a margin of 13 to 20 bps, depending on the loan balance. Such amounts are eliminated in consolidation at Sempra.

SDG&E and SoCalGas charge one another, as well as other Sempra affiliates, for shared asset depreciation. SoCalGas and SDG&E record revenues and the affiliates record corresponding amounts to O&M. Such amounts are eliminated in consolidation at Sempra.

SDG&E has a 20-year contract that commenced in June 2015 for up to 155 MW of renewable power supplied from the ESJ wind power generation facility, a consolidated subsidiary of Sempra. A second 20-year contract between SDG&E and ESJ for up to 108 MW of renewable power supplied from the same facility commenced in January 2022. Such amounts are eliminated in consolidation at Sempra.

The natural gas supply for SDG&E’s and SoCalGas’ core natural gas customers is purchased by SoCalGas as a combined procurement portfolio managed by SoCalGas. Core customers are primarily residential and small commercial and industrial customers. This core gas procurement function is considered a shared service; therefore, SoCalGas records revenues net of costs in cost of sales. Such amounts are eliminated in consolidation at Sempra.

SoCalGas provides natural gas transportation and storage services to SDG&E and charges SDG&E for such services monthly. SoCalGas records revenues and SDG&E records a corresponding amount to cost of sales. Such amounts are eliminated in consolidation at Sempra.

SoCalGas provides transportation services to Ecogas. SoCalGas records revenues and Ecogas records a corresponding amount to cost of sales. Such amounts are eliminated in consolidation at Sempra.

SoCalGas and Sempra Infrastructure may buy and sell natural gas from and to each other in open market transactions to help satisfy supply needs. SoCalGas records revenues and costs in cost of sales. Sempra Infrastructure records revenues and costs in revenues. Such amounts are eliminated in consolidation at Sempra.

Sempra Infrastructure has agreements with Cameron LNG JV to provide certain business services and project development services related to the Cameron LNG Phase 2 project.

Sempra Infrastructure provides maintenance and administrative services to TAG Pipelines. Additionally, Sempra Infrastructure subleases office space for personnel to TAG Pipelines and TAG Norte.

Sempra provides guarantees related to Cameron LNG JV’s SDSRA and CFIN’s Support Agreement. We discuss these guarantees in Note 5.

2024 Form 10-K | F-35

INVENTORIES

SDG&E and SoCalGas value natural gas inventory using the last-in first-out method. Sempra Infrastructure values natural gas inventory at the lower of average cost or net realizable value. We record natural gas to inventory when injected and then to expense when the gas is withdrawn for distribution to customers or to be used as fuel for electric generation.

Sempra Infrastructure values LNG inventory at the lower of average cost or net realizable value. We record LNG to inventory when delivered to our terminals and then to expense when transported from our terminals.

SDG&E, SoCalGas and Sempra Infrastructure generally value materials and supplies at the lower of average cost or net realizable value. We record materials and supplies to inventory when purchased and then to expense or capitalized to PP&E, as appropriate, when used.

The components of inventories are as follows:

INVENTORY BALANCES AT DECEMBER 31
(Dollars in millions)
	Sempra				SDG&E				SoCalGas
	2024		2023		2024		2023		2024		2023
Natural gas	$	163	$	174	$	1	$	1	$	148	$	155
LNG	27		9		—		—		—		—
Materials and supplies	369		299		201		152		139		122
Total	$	559	$	482	$	202	$	153	$	287	$	277

GREENHOUSE GAS ALLOWANCES AND OBLIGATIONS

SDG&E, SoCalGas and Sempra Infrastructure are required by AB 32 to acquire GHG allowances for every metric ton of carbon dioxide equivalent emitted into the atmosphere during electric generation and natural gas consumption. SDG&E and SoCalGas receive allocations of GHG allowances on behalf of their customers at no cost and purchase any additional allowances required. We record purchased and allocated GHG allowances at the lower of weighted-average cost or market. We measure the compliance obligation, which is based on emissions, at the carrying value of allowances held plus the fair value of additional allowances necessary to satisfy the obligation. SDG&E and SoCalGas balance costs and revenues associated with the GHG program through regulatory balancing accounts. Sempra Infrastructure records the cost of GHG obligations in cost of sales. We remove the assets and liabilities from the balance sheets as the allowances are surrendered.

WILDFIRE FUND

In July 2019, the Wildfire Legislation was signed into law to address certain issues related to catastrophic wildfires in California and their impact on electric IOUs. Investor-owned gas distribution utilities such as SoCalGas are not covered by this legislation. The issues addressed include wildfire mitigation, cost recovery standards and requirements, a wildfire fund, a cap on liability, and the establishment of a wildfire safety board.

The Wildfire Legislation established a revised legal standard for the recovery of wildfire costs (Revised Prudent Manager Standard) and established a fund (the Wildfire Fund) designed to provide liquidity to SDG&E, PG&E and Edison to pay IOU wildfire-related claims in the event that the governmental agency responsible for determining causation determines the applicable IOU’s equipment caused the ignition of a wildfire, primary insurance coverage is exceeded and certain other conditions are satisfied. A primary purpose of the Wildfire Fund is to pool resources provided by shareholders and ratepayers of the IOUs and make those resources available to reimburse the IOUs for third-party wildfire claims incurred after July 12, 2019, the effective date of the Wildfire Legislation, subject to certain limitations.

2024 Form 10-K | F-36

An IOU may seek payment from the Wildfire Fund for settled or adjudicated third-party damage claims arising from certain wildfires that exceed, in aggregate in a calendar year, the greater of $1.0 billion or the IOU’s required amount of insurance coverage as recommended by the Wildfire Fund’s administrator. Wildfire claims approved by the Wildfire Fund’s administrator will be paid by the Wildfire Fund to the IOU to the extent funds are available. These utilized funds will be subject to review by the CPUC, which will make a determination as to the degree an IOU’s conduct related to an ignition of a wildfire was prudent or imprudent. The Revised Prudent Manager Standard requires that the CPUC apply clear standards when reviewing wildfire liability losses paid when determining the reasonableness of an IOU’s conduct related to an ignition. Under this standard, the conduct under review related to the ignition may include factors within and beyond the IOU’s control, including humidity, temperature and winds. Costs and expenses may be allocated for cost recovery in full or in part. Also, under this standard, an IOU’s conduct will be deemed reasonable if a valid annual safety certification is in place at the time of the ignition, unless a serious doubt is raised, in which case the burden shifts to the utility to dispel that doubt. The IOUs will receive an annual safety certification from OEIS if they meet various requirements.

If an IOU has maintained a valid annual safety certification, to the extent it is found to be imprudent, claims will be reimbursable by the IOU to the Wildfire Fund up to a cap based on the IOU’s rate base. The aggregate requirement to reimburse the Wildfire Fund over a trailing three calendar year period is capped at 20% of the equity portion of an IOU’s electric transmission and distribution rate base in the year of the prudency determination. Based on its 2024 rate base, the liability cap for SDG&E is approximately $1.4 billion, which is adjusted annually. The liability cap will apply on a rolling three-year basis so long as future annual safety certifications are received and the Wildfire Fund has not been terminated, which could occur if funds are exhausted. Amounts in excess of the liability cap and amounts that are determined to be prudently incurred do not need to be reimbursed by an IOU to the Wildfire Fund. The Wildfire Fund does not have a specified term and coverage will continue until the assets of the Wildfire Fund are exhausted and the Wildfire Fund is terminated, in which case, the remaining funds, if any, will be transferred to California’s general fund to be used for fire risk mitigation programs.

In October 2024, the OEIS approved an update to SDG&E’s 2023-2025 wildfire mitigation plan, which is effective until the OEIS approves a new plan. In December 2024, SDG&E received its annual wildfire safety certification from the OEIS.

The Wildfire Fund was initially funded up to $10.5 billion by a loan from the California Surplus Money Investment Fund. The loan is financed through a DWR bond, which was put in place in October 2020 and is securitized through a dedicated surcharge on ratepayers’ bills attributable to the DWR. In October 2019, the CPUC adopted a decision authorizing a non-bypassable charge to be collected by the IOUs to support the anticipated DWR bond issuance authorized by AB 1054. The CPUC decision also determined that ratepayers of non-participating electrical corporations shall not pay the non-bypassable charge.

The Wildfire Fund was also funded by initial shareholder contributions from the IOUs totaling $7.5 billion. SDG&E’s share was $322.5 million. The IOUs are also required to make annual shareholder contributions to the Wildfire Fund with an aggregate value of $3 billion over a 10-year period starting in 2019. SDG&E’s share is $129 million. The contributions are not subject to rate recovery.

Wildfire Fund Asset and Obligation

In 2019, SDG&E recorded both a Wildfire Fund asset and a related obligation for its commitment to make shareholder contributions of $451.5 million to the Wildfire Fund. SDG&E paid its initial shareholder contribution of $322.5 million to the Wildfire Fund in September 2019. SDG&E funded this contribution with proceeds from an equity contribution from Sempra. SDG&E expects to continue to make annual shareholder contributions of $12.9 million through December 31, 2028. SDG&E is accreting the present value of the Wildfire Fund obligation until the liability is settled.

SDG&E is amortizing the Wildfire Fund asset on a straight-line basis over the estimated period of benefit, as adjusted for utilization by the IOUs. In 2024, SDG&E revised its estimate of the period of benefit from 15 years to 25 years. The estimated period of benefit of the Wildfire Fund asset is based on several assumptions, including, but not limited to:

▪historical wildfire experience of each IOU in California, including frequency and severity of the wildfires

▪the value of property potentially damaged by wildfires

▪the effectiveness of wildfire risk mitigation efforts by each IOU

▪liability cap of each IOU

▪IOU prudency determination levels

▪FERC jurisdictional allocation levels

▪insurance coverage levels

2024 Form 10-K | F-37

The use of different assumptions, or changes to the assumptions used, could have a significant impact on the estimated period of benefit of the Wildfire Fund asset. SDG&E periodically evaluates the estimated period of benefit of the Wildfire Fund asset based on actual experience and changes in these assumptions. SDG&E recognizes a reduction of its Wildfire Fund asset and records a charge against earnings in the period when there is a reduction of the available coverage due to recoverable claims from any of the participating IOUs. Wildfire claims that are recoverable from the Wildfire Fund, net of anticipated or actual reimbursement to the Wildfire Fund by the responsible IOU, decrease the Wildfire Fund asset and remaining available coverage.

The following table summarizes the location of balances related to the Wildfire Fund on Sempra’s and SDG&E’s Consolidated Balance Sheets.

WILDFIRE FUND
(Dollars in millions)
		December 31,
	Location	2024		2023
Wildfire Fund asset:
Current	Prepaid Expenses	$	14	$	28
Noncurrent	Wildfire Fund	262		269
Wildfire Fund obligation:
Current	Other Current Liabilities	13		13
Noncurrent	Deferred Credits and Other	31		42

NOTE RECEIVABLE

In November 2021, Sempra loaned $300 million to KKR Pinnacle in exchange for an interest-bearing promissory note that is due in full no later than October 2029 and bears compound interest at 5% per annum, which may be paid quarterly or added to the outstanding principal at the election of KKR Pinnacle. At December 31, 2024 and 2023, Other Long-Term Assets includes $349 million and $332 million, respectively, of outstanding principal, compounded interest and unamortized transaction costs, net of allowance for credit losses, on Sempra’s Consolidated Balance Sheets.

LONG-LIVED ASSETS

We test long-lived assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of long-lived assets. Long-lived assets include intangible assets subject to amortization, but do not include investments in unconsolidated entities. A long-lived asset may be impaired when the estimated future undiscounted cash flows are less than the carrying amount of the asset. If that comparison indicates that the asset’s carrying value may not be recoverable, the impairment is measured based on the difference between the carrying amount and the fair value of the asset. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

Goodwill is the excess of the purchase price over the fair value of the identifiable net assets of acquired companies measured at the time of acquisition. Goodwill is not amortized, but we test it for impairment annually on October 1 or whenever events or changes in circumstances necessitate an evaluation. If the carrying value of the reporting unit, including goodwill, exceeds its fair value, we record a goodwill impairment loss as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill.

For our annual goodwill impairment testing, we have the option to first make a qualitative assessment of whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount before applying the quantitative goodwill impairment test. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market considerations, cost factors and the overall financial performance of the reporting unit. If, after assessing these qualitative factors, we determine that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, then we perform the quantitative goodwill impairment test. If, after performing the quantitative goodwill impairment test, we determine that goodwill is impaired, we record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill.

Goodwill of $1,602 million at both December 31, 2024 and 2023 primarily relates to the 2016 acquisitions of IEnova Pipelines and the Ventika wind power generation facilities at Sempra Infrastructure.

2024 Form 10-K | F-38

Other Intangible Assets

Other Intangible Assets included on Sempra’s Consolidated Balance Sheets are as follows:

OTHER INTANGIBLE ASSETS
(Dollars in millions)
	Amortization period (years)	December 31,
		2024		2023
Sempra:
Renewable energy transmission and consumption permits	15 to 19	$	169	$	169
O&M agreement	23	66		66
ESJ PPA	14	190		190
Other	10 to indefinite	15		15
		440		440
Less accumulated amortization:
Renewable energy transmission and consumption permits		(68)		(59)
O&M agreement		(20)		(17)
ESJ PPA		(51)		(37)
Other		(9)		(9)
		(148)		(122)
		$	292	$	318

Other Intangible Assets at December 31, 2024 primarily include:

▪renewable energy transmission and consumption permits granted by the CRE at the Ventika wind power generation facilities, Don Diego Solar and Border Solar;

▪a favorable O&M agreement acquired in connection with the acquisition of Ductos y Energéticos del Norte, S. de R.L. de C.V.; and

▪the relative fair value of the PPA that was acquired in connection with the acquisition of ESJ.

Intangible assets subject to amortization are amortized over their estimated useful lives. Amortization expense for intangible assets was $26 million (including $13.5 million recorded against revenues) in each of 2024, 2023, and 2022. We estimate amortization expense for each of the next five years to be approximately $26 million per year (including $13.5 million per year recorded against revenues).

2024 Form 10-K | F-39

PROPERTY, PLANT AND EQUIPMENT

PP&E is recorded at cost and primarily represents the buildings, equipment, other facilities and information systems used by SDG&E and SoCalGas to provide natural gas and electric utility services, and by Other Sempra businesses in their operations, including construction work in progress, leasehold improvements and other equipment. Our PP&E costs include labor, materials and contract services and expenditures for replacement parts incurred during a major maintenance outage of a plant. In addition, the cost of utility plant at our rate-regulated businesses and PP&E under regulated projects that meet the regulatory accounting requirements of U.S. GAAP includes AFUDC. The cost of PP&E for our non-regulated projects includes capitalized interest. Maintenance costs are expensed as incurred. The cost of most retired depreciable utility plant assets less salvage value is charged to accumulated depreciation. We discuss assets collateralized as security for certain indebtedness in Note 6.

PROPERTY, PLANT AND EQUIPMENT BY MAJOR FUNCTIONAL CATEGORY
(Dollars in millions)
	December 31,				Depreciation rates for years ended December 31,
	2024		2023		2024		2023		2022
SDG&E:
Natural gas operations	$	4,531	$	4,175	2.62	%	2.60	%	2.57	%
Electric distribution	12,542		11,597		4.21		4.05		3.94
Electric transmission(1)	8,878		8,504		3.06		3.04		3.03
Electric generation	2,527		2,515		5.43		5.18		5.11
Other electric	2,722		2,507		6.95		7.05		7.03
Construction work in progress(1)	1,962		1,620		N/A		N/A		N/A
Total SDG&E	33,162		30,918
SoCalGas:
Natural gas operations	27,191		25,506		3.68		3.64		3.57
Other non-utility	32		50		0.98		1.03		1.54
Construction work in progress	1,861		1,469		N/A		N/A		N/A
Total SoCalGas	29,084		27,025
Other Sempra(2):					Estimated useful lives				Weighted-average useful life
Land and land rights	498		488		16 to 44 years(3)				37
Machinery and equipment:
Pipelines and storage	4,355		3,883		41 to 49 years				42
Generating plants	1,820		1,815		11 to 28 years				26
LNG terminal	1,156		1,139		42 years				42
Refined products terminals	876		656		37 years				37
Other	348		346		1 to 21 years				15
Construction work in progress	8,781		5,930		N/A				N/A
Other	317		295		1 to 35 years				16
	18,151		14,552
Total Sempra	$	80,397	$	72,495

(1)    At December 31, 2024, includes $563 in electric transmission assets and $1 in construction work in progress related to SDG&E’s 86% interest in the Southwest Powerlink transmission line, jointly owned by SDG&E with other utilities. SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for its share of the project and participates in decisions concerning operations and capital expenditures. SDG&E’s share of operating expenses is included in SDG&E’s and Sempra’s Consolidated Statements of Operations.

(2)    Includes $290 and $310 at December 31, 2024 and 2023, respectively, of utility plant, primarily pipelines and other distribution assets at Ecogas.

(3)    Estimated useful lives are for land rights.

2024 Form 10-K | F-40

Sempra Infrastructure’s Sonora natural gas pipeline consists of two pipeline segments, the Sasabe-Puerto Libertad-Guaymas segment and the Guaymas-El Oro segment. Each segment has its own service agreement with the CFE. Following the start of commercial operations of the Guaymas-El Oro segment, Sempra Infrastructure reported damage to the pipeline in the Yaqui territory that has made that section inoperable since August 2017 because it was not able to be repaired due to legal challenges, which were resolved in March 2023, by some members of the Yaqui tribe. Sempra Infrastructure and the CFE have agreed to an amendment to their transportation services agreement and to re-route the portion of the pipeline that is in the Yaqui territory, whereby the CFE would pay for the re-routing with a new tariff. This amendment will terminate if certain conditions are not met, and Sempra Infrastructure retains the right to terminate the transportation services agreement and seek to recover its reasonable and documented costs and lost profit. Sempra Infrastructure continues to acquire and pursue the necessary rights-of-way and permits for the portion of the pipeline that needs to be re-routed. At December 31, 2024, Sempra Infrastructure had $401 million in PP&E, net, related to the Guaymas-El Oro segment of the Sonora pipeline, which could be subject to impairment if Sempra Infrastructure is unable to re-route a portion of the pipeline and resume operations or if Sempra Infrastructure terminates the contract and is unable to obtain recovery.

Depreciation expense is computed using the straight-line method over the asset’s estimated composite useful life, the CPUC-prescribed period for SDG&E and SoCalGas, or the remaining term of the site leases, whichever is shortest.

DEPRECIATION EXPENSE
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra	$	2,409	$	2,202	$	1,995
SDG&E	1,216		1,092		977
SoCalGas	903		833		755

ACCUMULATED DEPRECIATION AND AMORTIZATION
(Dollars in millions)
	December 31,
	2024		2023
SDG&E:
Accumulated depreciation:
Natural gas operations	$	1,121	$	1,048
Electric transmission, distribution and generation(1)	6,930		6,321
Total SDG&E	8,051		7,369
SoCalGas:
Accumulated depreciation:
Natural gas operations	8,315		7,835
Other non-utility	15		17
Total SoCalGas	8,330		7,852
Other Sempra:
Accumulated depreciation – other(2)	2,579		2,314
Total Sempra	$	18,960	$	17,535

(1)    Includes $338 at December 31, 2024 related to SDG&E’s 86% interest in the Southwest Powerlink transmission line, jointly owned by SDG&E and other utilities.

(2)    Includes $75 and $82 at December 31, 2024 and 2023, respectively, of accumulated depreciation for utility plant at Ecogas.

SDG&E and SoCalGas finance construction projects with debt and equity funds. The CPUC and the FERC allow the recovery of the cost of these funds by the capitalization of AFUDC, calculated using rates authorized by the CPUC and the FERC, as a cost component of PP&E. SDG&E and SoCalGas earn a return on the capitalized AFUDC after the utility property is placed in service and recover the AFUDC from their customers over the expected useful lives of the assets.

Pipeline projects under construction by Sempra Infrastructure that are both subject to certain regulation and meet U.S. GAAP regulatory accounting requirements record the impact of AFUDC.

We capitalize interest costs incurred to finance capital projects and interest at equity method investments that have not commenced planned principal operations.

2024 Form 10-K | F-41

The table below summarizes capitalized financing costs, comprised of capitalized interest and AFUDC related to debt.

CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra	$	629	$	448	$	255
SDG&E	100		116		116
SoCalGas	101		77		73

ASSET RETIREMENT OBLIGATIONS

For tangible long-lived assets, we record AROs for the present value of liabilities of future costs expected to be incurred when assets are retired from service if the retirement process is legally required and if a reasonable estimate of fair value can be made. We also record a liability if a legal obligation to perform an asset retirement exists and can be reasonably estimated but performance is conditional upon a future event. We record the estimated retirement cost using the present value of the obligation at the time the asset is placed into service and recognize that cost over the life of the related asset by depreciating the asset retirement cost and accreting the obligation until the liability is settled. Our rate-regulated entities record regulatory assets or liabilities as a result of the timing difference between the recognition of costs in accordance with U.S. GAAP and costs recovered through the rate-making process.

We have recorded AROs related to various assets, including:

SDG&E and SoCalGas

▪fuel and storage tanks

▪natural gas transmission and distribution systems

▪hazardous waste storage facilities

▪asbestos-containing construction materials

SDG&E

▪nuclear power facilities

▪electric transmission and distribution systems

▪energy storage systems

▪power generation plants

SoCalGas

▪underground natural gas storage facilities and wells

Other Sempra

▪LNG terminal

▪natural gas transportation and distribution systems

▪LPG storage facilities

▪refined products terminals

▪power generating plants

2024 Form 10-K | F-42

The changes in AROs are as follows:

CHANGES IN ASSET RETIREMENT OBLIGATIONS
(Dollars in millions)
	Sempra						SDG&E						SoCalGas
	2024		2023		2022		2024		2023		2022		2024		2023		2022
Balance at January 1(1)	$	3,831	$	3,712	$	3,538	$	894	$	887	$	890	$	2,847	$	2,743	$	2,582
Accretion expense	156		148		141		37		37		37		114		106		101
Liabilities incurred	—		18		21		—		15		6		—		—		—
Payments	(65)		(62)		(57)		(57)		(59)		(54)		(8)		(3)		(3)
Revisions	3		15		69		26		14		8		(23)		1		63
Balance at December 31(1)	$	3,925	$	3,831	$	3,712	$	900	$	894	$	887	$	2,930	$	2,847	$	2,743

(1)    Current portion of the ARO for Sempra is included in Other Current Liabilities on the Consolidated Balance Sheets.

CONTINGENCIES

We accrue losses for the estimated impacts of various conditions, situations or circumstances involving uncertain outcomes. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date and if:

▪information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events; and

▪the amount of the loss or a range of possible losses can be reasonably estimated.

We do not accrue contingencies that might result in gains. We assess contingencies for litigation claims, environmental remediation and other events.

COMPREHENSIVE INCOME

Comprehensive income includes all changes in the equity of a business enterprise (except those resulting from investments by owners and distributions to owners), including:

▪foreign currency translation adjustments

▪certain hedging activities

▪changes in unamortized net actuarial gain or loss and prior service cost related to pension and PBOP plans

2024 Form 10-K | F-43

The Consolidated Statements of Comprehensive Income (Loss) show the changes in the components of OCI, including the amounts attributable to NCI. The following tables present the changes in AOCI by component and amounts reclassified out of AOCI to net income, after amounts attributable to NCI.

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
(Dollars in millions)
	Foreign currency translation adjustments		Financial instruments		Pension and PBOP		Total AOCI
Sempra:
Balance at December 31, 2021	$	(79)	$	(156)	$	(83)	$	(318)
OCI before reclassifications	10		147		(11)		146
Amounts reclassified from AOCI(2)	10		19		8		37
Net OCI(2)	20		166		(3)		183
Balance at December 31, 2022	(59)		10		(86)		(135)
OCI before reclassifications	23		59		(35)		47
Amounts reclassified from AOCI(3)	—		(66)		4		(62)
Net OCI(3)	23		(7)		(31)		(15)
Balance at December 31, 2023	(36)		3		(117)		(150)
OCI before reclassifications	(30)		34		(1)		3
Amounts reclassified from AOCI	—		(22)		3		(19)
Net OCI	(30)		12		2		(16)
Balance at December 31, 2024	$	(66)	$	15	$	(115)	$	(166)
SDG&E:
Balance at December 31, 2021					$	(10)	$	(10)
OCI before reclassifications					2		2
Amounts reclassified from AOCI					1		1
Net OCI					3		3
Balance at December 31, 2022					(7)		(7)
OCI before reclassifications					(2)		(2)
Amounts reclassified from AOCI					1		1
Net OCI					(1)		(1)
Balance at December 31, 2023					(8)		(8)
OCI before reclassifications					(3)		(3)
Amounts reclassified from AOCI					(1)		(1)
Net OCI					(4)		(4)
Balance at December 31, 2024					$	(12)	$	(12)
SoCalGas:
Balance at December 31, 2021			$	(13)	$	(18)	$	(31)
OCI before reclassifications			—		4		4
Amounts reclassified from AOCI			1		2		3
Net OCI			1		6		7
Balance at December 31, 2022			(12)		(12)		(24)
OCI before reclassifications			—		(1)		(1)
Amounts reclassified from AOCI			1		1		2
Net OCI			1		—		1
Balance at December 31, 2023			(11)		(12)		(23)
OCI before reclassifications			—		(5)		(5)
Amounts reclassified from AOCI			1		—		1
Net OCI			1		(5)		(4)
Balance at December 31, 2024			$	(10)	$	(17)	$	(27)

(1)    All amounts are net of income tax, if subject to tax, and after NCI.

(2)    Total AOCI includes $9 of foreign currency translation adjustments associated with the sale of NCI to ADIA in 2022. We discuss this transaction in Note 12 in “Noncontrolling Interests – SI Partners.” This transaction did not impact the Consolidated Statement of Comprehensive Income (Loss).

(3)    Total AOCI includes $(46) of financial instruments associated with sale of NCI to KKR Denali in 2023, which we discuss in Note 12 in “Noncontrolling Interests – SI Partners Subsidiaries.” This transaction did not impact the Consolidated Statement of Comprehensive Income (Loss).

2024 Form 10-K | F-44

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about AOCI components	Amounts reclassified from AOCI						Affected line item on Consolidated Statements of Operations
	Years ended December 31,
	2024		2023		2022
Sempra:
Foreign currency translation adjustments	$	—	$	—	$	1	Operation and maintenance
Financial instruments:
Interest rate instruments	$	(11)	$	1	$	1	Interest expense
Interest rate instruments	(23)		(48)		29		Equity earnings(1)
Foreign exchange instruments	(5)		1		(1)		Revenues: Energy-related businesses
	(2)		2		1		Other income, net
Foreign exchange instruments	(6)		2		—		Equity earnings(1)
Interest rate and foreign exchange instruments	—		(1)		(2)		Interest expense
	—		(6)		(12)		Other income, net
Total, before income tax	(47)		(49)		16
	11		6		(6)		Income tax expense
Total, net of income tax	(36)		(43)		10
	14		23		9		Earnings attributable to noncontrolling interests
Total, net of income tax and after NCI	$	(22)	$	(20)	$	19
Pension and PBOP(2):
Amortization of actuarial loss	$	6	$	3	$	7	Other income, net
Amortization of prior service cost	3		2		4		Other income, net
Settlement charges	9		—		—		Other income, net
Total, before income tax	18		5		11
	(15)		(1)		(3)		Income tax expense
Total, net of income tax	$	3	$	4	$	8
Total reclassifications for the period, net of income tax and after NCI	$	(19)	$	(16)	$	28
SDG&E:
Pension and PBOP(2):
Amortization of actuarial loss	$	1	$	—	$	1	Other income, net
Amortization of prior service cost	—		1		—		Other income, net
Total, before income tax	1		1		1
	(2)		—		—		Income tax (expense) benefit
Total reclassifications for the period, net of income tax	$	(1)	$	1	$	1
SoCalGas:
Financial instruments:
Interest rate instruments	$	1	$	1	$	1	Interest expense
Pension and PBOP(2):
Amortization of actuarial loss	$	1	$	1	$	2	Other income (expense), net
Amortization of prior service cost	1		1		1		Other income (expense), net
Total, before income tax	2		2		3
	(2)		(1)		(1)		Income tax (expense) benefit
Total, net of income tax	$	—	$	1	$	2
Total reclassifications for the period, net of income tax	$	1	$	2	$	3

(1)    Equity earnings at Oncor Holdings and our foreign equity method investees are recognized after tax.

(2)    Amounts are included in the computation of net periodic benefit cost (see “Pension and PBOP” in Note 8).

REVENUES

See Note 3 for a description of significant accounting policies for revenues.

2024 Form 10-K | F-45

RENEWABLE ENERGY CERTIFICATES

RECs are energy rights established by governmental agencies for the environmental and social promotion of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets.

Retail sellers of electricity obtain RECs through renewable energy PPAs, internal generation or separate purchases in the market to comply with the RPS Program established by the governmental agencies. RECs provide documentation for the generation of a unit of renewable energy that is used to verify compliance with the RPS Program. The cost of RECs at SDG&E, which is recoverable in rates, is recorded in Cost of Electric Fuel and Purchased Power on the Statements of Operations.

OPERATION AND MAINTENANCE EXPENSES

Operation and Maintenance includes O&M and general and administrative costs, consisting primarily of personnel costs, purchased materials and services, insurance, rent, provisions for expected credit losses and litigation expense (except for litigation expense included in Aliso Canyon Litigation and Regulatory Matters).

LEGAL FEES

Legal fees that are associated with a past event for which a liability has been recorded are accrued when it is probable that fees also will be incurred and amounts are estimable.

FOREIGN CURRENCY TRANSLATION AND TRANSACTIONS

Our natural gas distribution utility in Mexico, Ecogas, uses its local currency as its functional currency. The assets and liabilities of its foreign operations are translated into U.S. dollars at current exchange rates at the end of the reporting period, and revenues and expenses are translated at average exchange rates for the year. The resulting noncash translation adjustments do not enter into the calculation of earnings or retained earnings but are reflected in OCI and AOCI.

Cash flows of this consolidated foreign subsidiary are translated into U.S. dollars using average exchange rates for the period. We report the effect of exchange rate changes on cash balances held in foreign currencies in Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash on Sempra’s Consolidated Statements of Cash Flows.

Foreign currency transaction gains (losses), net, are included in Other Income, Net, on Sempra’s Consolidated Statements of Operations.

2024 Form 10-K | F-46

OTHER INCOME, NET

Other Income, Net, on the Consolidated Statements of Operations consists of the following:

OTHER INCOME (EXPENSE), NET
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra:
Allowance for equity funds used during construction	$	150	$	140	$	143
Investment gains (losses), net(1)	36		28		(42)
Gains on interest rate and foreign exchange instruments, net	2		4		11
Foreign currency transaction (losses) gains, net(2)	(16)		2		(24)
Non-service components of net periodic benefit cost	(101)		(106)		(59)
Interest on regulatory balancing accounts, net	75		79		26
Sundry, net	(10)		(16)		(31)
Total	$	136	$	131	$	24
SDG&E:
Allowance for equity funds used during construction	$	73	$	86	$	88
Non-service components of net periodic benefit cost	4		(19)		(11)
Interest on regulatory balancing accounts, net	23		42		18
Sundry, net	(10)		(12)		(3)
Total	$	90	$	97	$	92
SoCalGas:
Allowance for equity funds used during construction	$	72	$	54	$	55
Non-service components of net periodic benefit cost	(86)		(80)		(42)
Interest on regulatory balancing accounts, net	52		37		8
Sundry, net	(13)		(15)		(29)
Total	$	25	$	(4)	$	(8)

(1)    Represents net investment gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are offset by corresponding changes in compensation expense related to the plans, recorded in O&M on the Consolidated Statements of Operations.

(2)    Includes losses of $11 in 2022 from translation to U.S. dollars of a Mexican peso-denominated loan to IMG, which are offset by corresponding amounts included in Equity Earnings on the Consolidated Statements of Operations.

INCOME TAXES

Income tax expense includes current and deferred income taxes. We record deferred income taxes for temporary differences between the book and the tax basis of assets and liabilities. ITCs from prior years are generally amortized to income by SDG&E and SoCalGas over the estimated service lives of the properties as required by the CPUC. However, in 2023, the scope of projects eligible for ITCs was expanded to include standalone energy storage projects, which are transferable under the IRA. The IRA also provided an election that permits ITCs related to standalone energy storage projects to be returned to utility customers over a period that is shorter than the life of the applicable asset.

Under the regulatory accounting treatment required for flow-through temporary differences, the Registrants recognize:

▪regulatory assets to offset deferred income tax liabilities if it is probable that the amounts will be recovered from customers; and

▪regulatory liabilities to offset deferred income tax assets if it is probable that the amounts will be returned to customers.

When there are uncertainties related to potential income tax benefits, the position we take must have at least a more-likely-than-not chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities in order to qualify for recognition. The term “more-likely-than-not” means a likelihood of more than 50%. Otherwise, we may not recognize any of the potential tax benefit associated with the position. We recognize a benefit for a tax position that meets the more-likely-than-not criterion at the largest amount of tax benefit that is greater than 50% likely of being realized upon its effective resolution.

Unrecognized income tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our ETR.

2024 Form 10-K | F-47

We accrue income tax to the extent we intend to repatriate cash to the U.S. from our continuing international operations. We currently do not record deferred income taxes for other basis differences between financial statement and income tax investment amounts in non-U.S. subsidiaries because they are indefinitely reinvested. We recognize income tax expense for basis differences related to global intangible low-taxed income as a period cost if and when incurred.

We recognize interest and penalties related to income taxes in income tax expense.

We provide additional information about income taxes in Note 7.

RESTRICTED NET ASSETS

Sempra

As we discuss below, SDG&E, SoCalGas and certain Other Sempra entities have restrictions on the amount of funds that can be transferred to Sempra by dividend, advance or loan as a result of conditions imposed by various regulators. Additionally, certain Other Sempra entities are subject to various financial and other covenants and other restrictions contained in debt and credit agreements (described in Note 6) and in other agreements that limit the amount of funds that can be transferred to Sempra. At December 31, 2024, Sempra was in compliance with all covenants related to its debt agreements.

At December 31, 2024, the amount of restricted net assets of consolidated entities of Sempra that may not be distributed to Sempra in the form of a loan or dividend is $17.9 billion. Additionally, the amount of restricted net assets of our unconsolidated entities is $16.3 billion. Although the restrictions cap the amount of funding that the various operating subsidiaries can provide to Sempra, we do not believe these restrictions will have a significant impact on our ability to access cash to pay dividends and fund operating needs.

As we discuss in Note 5, $2.9 billion of Sempra’s retained earnings represents undistributed earnings of equity method investments at December 31, 2024.

SDG&E and SoCalGas

The CPUC’s regulation of SDG&E’s and SoCalGas’ capital structures limits the amounts available for dividends and loans to Sempra. At December 31, 2024, Sempra could have received combined loans and dividends of approximately $672 million from SDG&E and approximately $457 million from SoCalGas.

The payment and amount of future dividends by SDG&E and SoCalGas are at the discretion of their respective boards of directors. The following restrictions limit the amount of retained earnings that may be paid as common stock dividends or loaned to Sempra from either utility:

▪The CPUC requires that SDG&E’s and SoCalGas’ common equity ratios be no lower than one percentage point below the CPUC-authorized percentage of each entity’s authorized capital structure. The authorized percentage at December 31, 2024 is 52% at both SDG&E and SoCalGas.

▪SDG&E and SoCalGas each have a revolving credit line that requires it to maintain a ratio of consolidated indebtedness to consolidated capitalization (as defined in the agreements) of no more than 65%, as we discuss in Note 6.

Based on these restrictions, at December 31, 2024, SDG&E’s restricted net assets were $10.0 billion, and SoCalGas’ restricted net assets were $7.7 billion, which could not be transferred to Sempra.

2024 Form 10-K | F-48

Other Sempra

Sempra owns a 100% interest in Oncor Holdings, which owns an 80.25% interest in Oncor. As we discuss in Note 5, we account for our investment in Oncor Holdings under the equity method. Significant restrictions at Oncor that limit the amount that may be paid as dividends to Sempra include:

▪In connection with ring-fencing measures, governance mechanisms and commitments, Oncor may not pay any dividends or make any other distributions (except for contractual tax payments) if a majority of its independent directors or a minority member director determines that it is in the best interests of Oncor to retain such amounts to meet expected future requirements.

▪Oncor must remain in compliance with its debt-to-equity ratio established by the PUCT for ratemaking purposes and may not pay dividends or other distributions (except for contractual tax payments) if that payment would cause it to exceed its PUCT authorized debt-to-equity ratio. Oncor’s authorized regulatory capital structure is 57.5% debt to 42.5% equity at December 31, 2024.

▪If the credit rating on Oncor’s senior secured debt by any of the Rating Agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT. At December 31, 2024, all of Oncor’s senior secured ratings were above BBB.

▪Oncor’s revolving credit lines and certain of its other debt agreements require it to maintain a consolidated senior debt-to-capitalization ratio of no more than 65% and observe certain affirmative covenants. At December 31, 2024, Oncor was in compliance with these covenants.

Based on these restrictions, at December 31, 2024, Oncor’s restricted net assets were $15.6 billion, which could not be transferred to its owners.

Sempra owns a 50% interest in Sharyland Holdings, which owns a 100% interest in Sharyland Utilities. Significant restrictions related to this equity method investment include:

▪Sharyland Utilities may not pay dividends or make other distributions (except for contractual payments) without the consent of the JV partner.

▪Sharyland Utilities must remain in compliance with the capital structure established by the PUCT for ratemaking purposes and may not pay dividends or other distributions (except for contractual tax payments) if that payment would cause its debt to exceed 60% of its capital structure.

▪Sharyland Utilities has a revolving credit line and three senior notes that require it to maintain a consolidated debt-to-capitalization ratio of no more than 70% and observe certain customary reporting requirements and other affirmative covenants. At December 31, 2024, Sharyland Utilities was in compliance with these and all other covenants.

Based on these restrictions, at December 31, 2024, Sharyland Utilities’ restricted net assets were $136 million, which could not be transferred to its owners.

Significant restrictions at Sempra Infrastructure include:

▪Partnerships and JVs at Sempra Infrastructure may not pay dividends or make other distributions (except for contractual payments) without the consent of the partners.

▪Sempra Infrastructure has an equity method investment in Cameron LNG JV, which has debt agreements that require the establishment and funding of project accounts to which the proceeds of loans, project revenues and other amounts are deposited and applied in accordance with the debt agreements. The debt agreements require the JV to maintain reserve accounts in order to pay the project debt service, and also contain restrictions related to the payment of dividends and other distributions to the members of the JV.

Pursuant to the transfer restriction agreement under the debt agreements, Sempra must retain at least 10% of the indirect fully diluted economic and beneficial ownership interest in Cameron LNG JV. In addition, at all times, a Sempra controlled (but not necessarily wholly owned) subsidiary must directly own 50.2% of the membership interests of Cameron LNG JV.

To support Cameron LNG JV’s obligations under its debt agreements, Cameron LNG JV has granted security over all of its assets, subject to customary exceptions, and all equity interests in Cameron LNG JV were pledged to HSBC Bank USA, National Association, as security trustee for the benefit of all of Cameron LNG JV’s creditors. As a result, an enforcement action by the lenders taken in accordance with the finance documents could result in the exercise of such security interests by the lenders and the loss of ownership interests in Cameron LNG JV by Sempra and the other project partners.

Under these restrictions, net assets of Cameron LNG JV of approximately $443 million were restricted at December 31, 2024.

▪Mexico requires domestic corporations to maintain minimum legal reserves as a percentage of capital stock, resulting in restricted net assets of $185 million at Sempra Infrastructure’s consolidated Mexican subsidiaries at December 31, 2024.

▪IEnova has restrictions under trust agreements related to pipeline projects to pay for rights-of-way and other costs. Under these restrictions, net assets totaling $3 million were restricted at December 31, 2024.

2024 Form 10-K | F-49

▪TAG Norte, a 50% owned and unconsolidated JV of Sempra Infrastructure, has a long-term debt agreement that requires it to maintain a reserve account to pay the projects’ debt. Under these restrictions, net assets totaling $126 million were restricted at December 31, 2024.

▪Port Arthur LNG has a seven-year term loan facility agreement and working capital credit facility agreement that require consent of a trustee for the withdrawal or transfer of cash. Under these restrictions, net assets totaling $19 million were restricted at December 31, 2024.

NOTE 2. NEW ACCOUNTING STANDARDS

We describe below recent accounting pronouncements that have had or may have a significant effect on our results of operations, financial condition, cash flows or disclosures.

ASU 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures”: ASU 2023-07 revises reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. In addition, public entities are required to disclose the title and position of the CODM and explain how the CODM uses the reported measures of profit or loss to assess segment performance. The standard also requires interim disclosure of certain segment-related disclosures that previously were required only on an annual basis. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. We adopted the standard on December 31, 2024 and revised our segment reporting disclosures in Note 16 on a retrospective basis.

ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures”: ASU 2023-09 improves the transparency of income tax disclosures by requiring disaggregated information about each Registrant’s ETR reconciliation as well as information on income taxes paid. For each annual period, each Registrant will be required to disclose specific categories in the rate reconciliation and provide additional information for reconciling items that meet a quantitative threshold (if the effect of those reconciling items is equal to or greater than 5% of the amount computed by multiplying pretax income or loss by the applicable statutory income tax rate). ASU 2023-09 is effective for annual periods beginning after December 15, 2024. Early adoption is permitted for annual financial statements that have not yet been issued. We plan to adopt the standard on December 31, 2025 and are currently evaluating the effect of the standard on our financial reporting.

ASU 2024-03, “Disaggregation of Income Statement Expenses”: ASU 2024-03 mandates detailed disclosures on the disaggregation of income statement expenses. Public business entities are required to disclose in the notes to financial statements the amounts of purchases of inventory, employee compensation, depreciation and intangible asset amortization included in each relevant expense caption. The standard also requires disclosure of the amount, and a qualitative description of, other items remaining in relevant expense captions that are not separately disaggregated. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026, and interim periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted, and entities may adopt the standard on either a prospective or retrospective basis. We are currently evaluating the effect of the standard on our financial reporting and have not yet selected the year in which we will adopt the standard.

2024 Form 10-K | F-50

NOTE 3. REVENUES

The following tables disaggregate our revenues from contracts with customers by major service line and market. We also provide a reconciliation to total revenues by segment for Sempra. The majority of our revenue is recognized over time.

DISAGGREGATED REVENUES
(Dollars in millions)
	Sempra
	Sempra California		Sempra Infrastructure		Consolidating adjustments and Parent and other		Sempra
	Year ended December 31, 2024
By major service line:
Utilities	$	11,008	$	78	$	(23)	$	11,063
Energy-related businesses	—		818		(63)		755
Revenues from contracts with customers	$	11,008	$	896	$	(86)	$	11,818
By market:
Gas	$	6,858	$	471	$	(21)	$	7,308
Electric	4,150		425		(65)		4,510
Revenues from contracts with customers	$	11,008	$	896	$	(86)	$	11,818
Revenues from contracts with customers	$	11,008	$	896	$	(86)	$	11,818
Utilities regulatory revenues	374		—		—		374
Other revenues	—		986		7		993
Total revenues	$	11,382	$	1,882	$	(79)	$	13,185
	Year ended December 31, 2023
By major service line:
Utilities	$	13,686	$	87	$	(19)	$	13,754
Energy-related businesses	—		1,164		(70)		1,094
Revenues from contracts with customers	$	13,686	$	1,251	$	(89)	$	14,848
By market:
Gas	$	8,949	$	755	$	(17)	$	9,687
Electric	4,737		496		(72)		5,161
Revenues from contracts with customers	$	13,686	$	1,251	$	(89)	$	14,848
Revenues from contracts with customers	$	13,686	$	1,251	$	(89)	$	14,848
Utilities regulatory revenues	75		—		—		75
Other revenues	—		1,820		(23)		1,797
Total revenues	$	13,761	$	3,071	$	(112)	$	16,720
	Year ended December 31, 2022
By major service line:
Utilities	$	11,944	$	89	$	(15)	$	12,018
Energy-related businesses	—		1,760		(56)		1,704
Revenues from contracts with customers	$	11,944	$	1,849	$	(71)	$	13,722
By market:
Gas	$	7,267	$	1,270	$	(12)	$	8,525
Electric	4,677		579		(59)		5,197
Revenues from contracts with customers	$	11,944	$	1,849	$	(71)	$	13,722
Revenues from contracts with customers	$	11,944	$	1,849	$	(71)	$	13,722
Utilities regulatory revenues	633		—		—		633
Other revenues	—		70		14		84
Total revenues	$	12,577	$	1,919	$	(57)	$	14,439

2024 Form 10-K | F-51

DISAGGREGATED REVENUES
(Dollars in millions)
	SDG&E						SoCalGas
	Years ended December 31,
	2024		2023		2022		2024		2023		2022
By major service line:
Revenues from contracts with customers – Utilities	$	5,042	$	5,954	$	5,586	$	6,134	$	7,857	$	6,459
By market:
Gas	$	878	$	1,204	$	899	$	6,134	$	7,857	$	6,459
Electric	4,164		4,750		4,687		—		—		—
Revenues from contracts with customers	$	5,042	$	5,954	$	5,586	$	6,134	$	7,857	$	6,459
Revenues from contracts with customers	$	5,042	$	5,954	$	5,586	$	6,134	$	7,857	$	6,459
Utilities regulatory revenues	299		(357)		252		75		432		381
Total revenues	$	5,341	$	5,597	$	5,838	$	6,209	$	8,289	$	6,840

REVENUES FROM CONTRACTS WITH CUSTOMERS

Revenues from contracts with customers are primarily related to the transmission, distribution and storage of natural gas and the generation, transmission and distribution of electricity through our regulated utilities. We also provide other midstream and renewable energy-related services. We assess our revenues on a contract-by-contract basis as well as a portfolio basis to determine the nature, amount, timing and uncertainty, if any, of revenues being recognized.

We generally recognize revenues when performance of the promised commodity or service is provided to customers and invoices are issued for an amount that reflects the consideration we are entitled to in exchange for those services. We consider the delivery and transmission of natural gas and electricity and providing of natural gas storage services as ongoing and integrated services. Generally, natural gas or electricity services are received and consumed by the customer simultaneously. Performance obligations related to these services are satisfied over time and represent a series of distinct services that are substantially the same and that have the same pattern of transfer to the customers. We recognize revenue based on units delivered, as the satisfaction of respective performance obligations can be directly measured by the amount of natural gas or electricity delivered to the customer. In most cases, the right to consideration from the customer directly corresponds to the value transferred to the customer and we recognize revenue in the amount that we have the right to invoice.

The payment terms in customer contracts vary. Typically, we have an unconditional right to customer payments, which are due after the performance obligation to the customer is satisfied. The term between invoicing and when payment is due is typically between 10 and 90 days.

We exclude sales and usage-based taxes from revenues. In addition, SDG&E and SoCalGas pay franchise fees to operate in various municipalities. SDG&E and SoCalGas bill these franchise fees to their customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of SDG&E’s and SoCalGas’ ability to collect from customers, are accounted for on a gross basis and reflected in utilities revenues from contracts with customers and operating expense.

Utilities Revenues

Utilities revenues represent the majority of our consolidated revenues from contracts with customers and include:

▪The transmission, distribution and storage of natural gas at:

◦SDG&E 

◦SoCalGas

◦Sempra’s Ecogas

▪The generation, transmission and distribution of electricity at SDG&E.

Utilities revenues are derived from and recognized upon the delivery of natural gas or electricity services to customers. Amounts that we bill customers are based on tariffs set by regulators within the respective state or country. For SDG&E and SoCalGas, amounts that we bill to customers also include adjustments for previously recognized regulatory revenues.

2024 Form 10-K | F-52

SDG&E, SoCalGas and Ecogas recognize revenues based on regulator-approved revenue requirements, which allow the utilities to recover their reasonable operating costs and provides the opportunity to realize their authorized rates of return on their investments. While SDG&E’s and SoCalGas’ revenues are not affected by actual sales volumes, the pattern of their revenue recognition during the year is affected by seasonality. SDG&E and SoCalGas recognize annual authorized revenue from customers using seasonal factors established in applicable proceedings. This generally results in a significant portion of operating revenues being recognized in the third quarter of each year for SDG&E and in the first and fourth quarters of each year for SoCalGas.

SDG&E has an arrangement to provide the California ISO with the ability to control its high-voltage transmission lines for prices approved by the FERC. Revenue is recognized over time as access is provided to the California ISO.

Factors that can affect the amount, timing and uncertainty of revenues and cash flows include weather, seasonality and timing of customer billings and collections, which may result in unbilled revenues that can vary significantly from month to month and generally approximate one-half month’s deliveries.

SDG&E and SoCalGas recognize revenues from the sale of allocated California GHG emission allowances at quarterly auctions administered by CARB. GHG allowances are delivered to CARB in advance of the quarterly auctions, and SDG&E and SoCalGas have the right to payment when the GHG allowances are sold at auction. GHG revenue is recognized on a point in time basis within the quarter the auction is held. SDG&E and SoCalGas balance costs and revenues associated with the GHG program through regulatory balancing accounts.

Energy-Related Businesses Revenues

Revenues at Sempra Infrastructure typically represent revenues from long-term, U.S. dollar-based contracts with customers for the sale of natural gas and LNG, as well as storage and transportation of natural gas. Invoiced amounts are based on the volume of natural gas delivered and contracted prices.

We generate pipeline transportation revenues from firm agreements, under which customers pay a fee for reserving transportation capacity. Revenue is recognized when the volumes are delivered to the customers’ agreed upon delivery point. We recognize revenues for our stand-ready obligation to provide capacity and transportation services throughout the contractual delivery period, as the benefits are received and consumed simultaneously as customers utilize pipeline capacity for the transport and receipt of natural gas and LPG. Invoiced amounts are based on a variable usage fee and a fixed capacity charge, adjusted for the Consumer Price Index, the effects of any foreign currency impacts and the actual quantity of commodity transported.

Sempra Infrastructure develops, invests in and operates solar and wind facilities that have long-term PPAs to sell the electricity and the related green energy attributes they generate to customers, generally load serving entities, industrial and other customers. Load serving entities will sell electric service to their end-users and wholesale customers immediately upon receipt of our power delivery, and industrial and other customers immediately consume the electricity to run their facilities, and thus, we recognize the revenue under the PPAs as the electricity is generated and delivered. We invoice customers based on the volume of energy delivered at rates pursuant to the PPAs.

TdM is a natural gas-fired power plant that generates revenues from selling electricity and/or resource adequacy to the California ISO and to governmental, public utility and wholesale power marketing entities as the power is delivered at the interconnection point.

We recognize storage revenue from firm capacity reservation agreements, under which we collect a fee for reserving storage capacity for customers in our storage facilities. Under these firm agreements, customers pay a monthly fixed reservation fee based on the storage capacity reserved rather than the actual volumes stored. For the fixed-fee component, revenue is recognized on a straight-line basis over the term of the contract. We bill customers for any capacity used in excess of the contracted capacity and such revenues are recognized in the month of occurrence. We also recognize revenue for interruptible storage services.

Sempra Infrastructure sells natural gas to the CFE and other customers under supply agreements. Sempra Infrastructure recognizes the revenue from the sale of natural gas upon transfer of the natural gas via pipelines to customers at the agreed upon delivery points, and in the case of the CFE, at its thermoelectric power plants.

Remaining Performance Obligations    

We do not disclose information about remaining performance obligations for (a) contracts with an original expected length of one year or less, (b) variable consideration recognized at the amount at which we have the right to invoice for services performed, or (c) variable consideration allocated to wholly unsatisfied performance obligations.

2024 Form 10-K | F-53

For contracts greater than one year, at December 31, 2024, we expect to recognize revenue related to the fixed fee component of the consideration as shown below. Sempra’s remaining performance obligations primarily relate to capacity agreements for natural gas storage and transportation at Sempra Infrastructure and transmission line projects at SDG&E. SoCalGas did not have any remaining performance obligations for contracts greater than one year at December 31, 2024.

REMAINING PERFORMANCE OBLIGATIONS
(Dollars in millions)
	Sempra(1)		SDG&E
2025	$	403	$	4
2026	284		4
2027	285		4
2028	239		4
2029	211		4
Thereafter	2,101		52
Total revenues to be recognized	$	3,523	$	72

(1)    Excludes intercompany transactions.

Contract Liabilities from Revenues from Contracts with Customers

From time to time, we receive payments in advance of satisfying the performance obligations associated with customer contracts. We defer such revenues as contract liabilities and recognize them in earnings as the performance obligations are satisfied.

Activities within Sempra’s and SDG&E’s contract liabilities are presented below. There were no contract liabilities at SoCalGas in 2024, 2023 or 2022.

CONTRACT LIABILITIES
(Dollars in millions)
	2024		2023		2022
Sempra:
Contract liabilities at January 1	$	(198)	$	(252)	(278)
Revenue from performance obligations satisfied during reporting period	11		14		131
Payments received in advance	(7)		(21)		(105)
Contract modification	(2)		61		—
Contract liabilities at December 31(1)	$	(196)	$	(198)	$	(252)
SDG&E:
Contract liabilities at January 1	$	(75)	$	(79)	$	(83)
Revenue from performance obligations satisfied during reporting period	3		4		4
Contract liabilities at December 31(2)	$	(72)	$	(75)	$	(79)

(1)     Balances at December 31, 2024 and 2023 include $105 and $5, respectively, in Other Current Liabilities and $91 and $193, respectively, in Deferred Credits and Other.

(2)     Balances at December 31, 2024 and 2023 include $4 and $3, respectively, in Other Current Liabilities and $68 and $72, respectively, in Deferred Credits and Other.

Sempra Infrastructure previously recorded a contract liability for funds held as collateral in lieu of a customer’s letters of credit primarily associated with its LNG storage and regasification agreement. In December 2024, Sempra Infrastructure and the customer agreed to modify their LNG storage and regasification agreement by reducing the remaining term of the agreement from approximately three years to one year, now expiring in December 2025. As a result of the modification, Sempra Infrastructure will recognize approximately $107 million, which the customer paid in advance, in revenue over the remaining one-year term. The net effect to our contract liabilities is reflected in “contract modification” in the table above.

As we discuss in Note 1 in “Property, Plant and Equipment,” Sempra Infrastructure and the CFE have agreed to an amendment to their transportation services agreement for the Guaymas-El Oro segment of the Sonora pipeline. Sempra Infrastructure determined that the amended transportation services agreement met the definition of a lease. In December 2023, Sempra reclassified $61 million from contract liabilities to other noncurrent liabilities, both within Deferred Credits and Other on Sempra’s Consolidated Balance Sheet.

2024 Form 10-K | F-54

Receivables from Revenues from Contracts with Customers

The table below shows receivable balances, net of allowances for credit losses, associated with revenues from contracts with customers on the Consolidated Balance Sheets.

RECEIVABLES FROM REVENUES FROM CONTRACTS WITH CUSTOMERS
(Dollars in millions)
	December 31,
	2024		2023
Sempra:
Accounts receivable – trade, net(1)	$	1,787	$	1,951
Accounts receivable – other, net	12		15
Due from unconsolidated affiliates – current(2)	4		4
Other long-term assets(3)	18		—
Total	$	1,821	$	1,970
SDG&E:
Accounts receivable – trade, net(1)	$	774	$	870
Accounts receivable – other, net	11		13
Due from unconsolidated affiliates – current(2)	6		6
Other long-term assets(3)	4		—
Total	$	795	$	889
SoCalGas:
Accounts receivable – trade, net	$	932	$	985
Accounts receivable – other, net	1		2
Other long-term assets(3)	14		—
Total	$	947	$	987

(1)     At December 31, 2024 and 2023, includes $144 and $148, respectively, of receivables due from customers that were billed on behalf of CCAs, which are not included in revenues.

(2)     Amount is presented net of amounts due to unconsolidated affiliates on the Consolidated Balance Sheets, when right of offset exists.

(3)     In January 2024, the CPUC directed SDG&E and SoCalGas to offer long-term repayment plans to eligible residential customers with past-due balances.

REVENUES FROM SOURCES OTHER THAN CONTRACTS WITH CUSTOMERS

Certain of our revenues are derived from sources other than contracts with customers and are accounted for under other accounting standards outside the scope of ASC 606.

Utilities Regulatory Revenues

Alternative Revenue Programs

We recognize revenues from alternative revenue programs when the regulator-specified conditions for recognition have been met and adjust these revenues as they are recovered or refunded through future utility service.

Decoupled Revenues. As we discuss above, the regulatory framework requires SDG&E and SoCalGas to recover authorized revenue based on estimated annual demand forecasts approved in regular proceedings before the CPUC. However, actual demand for natural gas and electricity will generally vary from CPUC-approved forecasted demand due to the impacts from weather volatility, energy efficiency programs, rooftop solar and other factors affecting consumption. The CPUC regulatory framework provides for SDG&E and SoCalGas to use a “decoupling” mechanism, which allows SDG&E and SoCalGas to record revenue shortfalls or excess revenues resulting from any difference between actual and forecasted demand to be recovered or refunded in authorized revenue in a subsequent period based on the nature of the account.

Incentive Mechanisms. SoCalGas is subject to the GCIM and is eligible for financial awards or subject to financial penalties depending on its performance in relation to specific benchmarks.

Incentive awards are included in revenues when we receive required CPUC approval of the award, the timing of which may not be consistent from year to year. We would record penalties for results below the specified benchmarks against revenues when we believe it is probable that the CPUC would assess a penalty.

2024 Form 10-K | F-55

Other Cost-Based Regulatory Recovery

The CPUC, and the FERC as it relates to SDG&E, authorize SDG&E and SoCalGas to collect, or in the case of CPUC programmatic activities, to apply for additional, revenue requirements beyond base rates from customers for certain operating and capital related costs (depreciation, taxes and return on rate base), including for:

▪costs to purchase natural gas and electricity;

▪costs associated with administering public purpose, demand response, environmental compliance, and customer energy efficiency programs;

▪other programmatic activities, such as gas distribution, gas transmission, gas storage integrity management and wildfire mitigation; and

▪costs associated with third party liability insurance premiums.

Authorized costs are recovered as the commodity or service is delivered. To the extent authorized amounts collected vary from actual costs, the differences are generally recovered or refunded in a subsequent period based on the nature of the balancing account mechanism. In general, the revenue recognition criteria for balanced costs billed to customers are met when the costs are incurred. Because these costs are substantially recovered in rates through a balancing account mechanism, changes in these costs are reflected as changes in revenues. The CPUC and the FERC may impose various review procedures before authorizing recovery or refund of amounts accumulated for authorized programs, including limitations on the program’s total cost, revenue requirement limits or reviews of costs for reasonableness. These procedures could result in delays or disallowances of recovery from customers.

We discuss balancing accounts and their effects further in Note 4.

Other Revenues

Sempra Infrastructure generates lease revenues from certain of its natural gas and ethane pipelines, compressor stations, LPG storage facilities, a rail facility and refined products terminals. We discuss the recognition of lease income in Note 15.

Sempra Infrastructure has an agreement with Tangguh PSC to supply LNG to the ECA Regas Facility. Under the terms of the agreement, Tangguh PSC must either deliver the contracted number of cargoes or pay a diversion fee for non-delivery of LNG cargoes.

Sempra Infrastructure also recognizes other revenues associated with derivatives related to the sales of natural gas and electricity under short-term and long-term contracts and into the spot market and other competitive markets. Revenues include the net realized gains and losses on physical and derivative settlements and net unrealized gains and losses from the change in fair values of these derivatives.

2024 Form 10-K | F-56

NOTE 4. REGULATORY MATTERS

REGULATORY ASSETS AND LIABILITIES

We show the details of regulatory assets and liabilities in the following table and discuss them below. With the exception of regulatory balancing accounts, we generally do not earn a return on our regulatory assets until a related cash expenditure has been made. Upon the occurrence of a cash expenditure associated with a regulatory asset, the related amounts are recoverable through a regulatory account mechanism for which we earn a return authorized by applicable regulators, which generally approximates the three-month commercial paper rate. The periods during which we recognize a regulatory asset while we do not earn a return vary by regulatory asset.

REGULATORY ASSETS (LIABILITIES) AT DECEMBER 31
(Dollars in millions)
	Sempra				SDG&E				SoCalGas
	2024		2023		2024		2023		2024		2023
Fixed-price contracts and other derivatives	$	53	$	215	$	11	$	14	$	42	$	201
Deferred income taxes recoverable in rates	1,689		1,142		802		626		817		430
Pension and PBOP plan obligations	(458)		(212)		(2)		48		(456)		(260)
Employee benefit costs	19		24		3		3		16		21
Removal obligations	(3,295)		(3,082)		(2,676)		(2,468)		(619)		(614)
Environmental costs	149		139		115		105		34		34
Sunrise Powerlink fire mitigation	124		124		124		124		—		—
Regulatory balancing accounts(1)(2):
Commodity – electric	(313)		(233)		(313)		(233)		—		—
Commodity – gas, including transportation	(47)		(259)		86		52		(133)		(311)
Safety and reliability	820		959		227		207		593		752
Public purpose programs	(439)		(273)		(219)		(144)		(220)		(129)
2024 GRC retroactive impacts	631		—		277		—		354		—
Wildfire mitigation plan	808		685		808		685		—		—
Liability insurance premium	(24)		113		(15)		90		(9)		23
Other balancing accounts	158		373		(51)		(152)		209		525
Other regulatory assets (liabilities), net(2)	164		(10)		87		49		79		(58)
Total	$	39	$	(295)	$	(736)	$	(994)	$	707	$	614

(1)    At December 31, 2024 and 2023, the noncurrent portion of regulatory balancing accounts – net undercollected for Sempra was $1,731 and $1,913, respectively, for SDG&E was $873 and $950, respectively, and for SoCalGas was $858 and $963, respectively.

(2)    Includes regulatory assets earning a return authorized by applicable regulators, which generally approximates the three-month commercial paper rate.

Regulatory Assets Not Earning a Return

▪Regulatory assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from purchased power and natural gas commodity and transportation contracts. The regulatory asset is increased/decreased based on changes in the fair market value of the contracts. It is also reduced as payments are made for commodities and services under these contracts. The related amounts are recovered in rates once these contracts are settled, generally within four years.

▪Deferred income taxes recoverable/refundable in rates are based on current regulatory ratemaking and income tax laws. SDG&E, SoCalGas and Sempra Infrastructure expect to recover/refund net regulatory assets/liabilities related to deferred income taxes over the lives of the assets, ranging from 5 to 69 years, that give rise to the related accumulated deferred income tax balances. Regulatory assets and liabilities include excess deferred income taxes resulting from statutory income tax rate changes and certain income tax benefits and expenses associated with flow-through items, which we discuss in Note 7.

▪Regulatory assets/liabilities related to pension and PBOP plan obligations are offset by corresponding liabilities/assets. The assets are recovered in rates as the plans are funded.

▪The regulatory asset related to employee benefit costs represents our liability associated with long-term disability insurance that will be recovered from customers in future rates as expenditures are made.

▪Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs in excess of cumulative amounts incurred (or paid).

2024 Form 10-K | F-57

▪Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made.

▪The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a remaining 45-year period.

Regulatory Assets Earning a Return

▪Over- and undercollected regulatory balancing accounts and other regulatory assets, net, reflect the difference between customer billings and recorded or CPUC-authorized amounts. Depreciation, taxes and return on rate base may also be included in certain accounts. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval. The adopted revenue requirements in the 2024 GRC FD were placed into rates on February 1, 2025 and the incremental revenue requirements associated with the period from January 1, 2024 through January 31, 2025 are being recovered in rates over an 18-month period that began on February 1, 2025. SDG&E and SoCalGas periodically make requests to the CPUC to true up their revenue requirement for amounts accumulated in the regulatory balancing accounts and in other regulatory assets, net. The CPUC may impose various review procedures before authorizing recovery or refund of amounts accumulated for authorized programs, including limitations on the program’s total cost, revenue requirement limits or reviews of costs for reasonableness. These procedures could result in delays or disallowances of recovery from customers.

Amortization expense on certain regulatory assets for the years ended December 31, 2024, 2023 and 2022 was $14 million, $12 million and $11 million, respectively, at Sempra, $7 million, $6 million and $5 million, respectively, at SDG&E, and $7 million, $6 million and $6 million, respectively, at SoCalGas.

CPUC GRC

The CPUC uses GRCs to set revenues to allow SDG&E and SoCalGas to recover their reasonable operating costs and to provide the opportunity to realize their authorized rates of return on their investments. In December 2024, the CPUC approved an FD in the 2024 GRC for SDG&E and SoCalGas that authorizes SDG&E’s and SoCalGas’ revenue requirements for 2024 and attrition year adjustments for 2025 through 2027, inclusively.

The GRC FD adopts a 2024 revenue requirement of $2,699 million for SDG&E’s combined operations ($2,193 million for its electric operations and $506 million for its natural gas operations). SDG&E’s authorized 2024 combined revenue requirement represents an increase of $189 million (7.5%) over its authorized 2023 combined revenue requirement. In connection with SDG&E’s election to change its tax accounting method for gas repairs expenditures, the 2024 combined revenue requirement increase is net of $68 million of income tax benefits for 2023 and 2024 to be flowed through to customers. The GRC FD also specifies an increase in SDG&E’s 2025, 2026, and 2027 combined revenue requirements of $147 million (5.45%), $119 million (4.17%) and $122 million (4.11%), respectively, over the preceding year’s combined revenue requirement. The 2025, 2026 and 2027 revenue requirements will be updated to implement a previously authorized change in the cost of capital, which we describe below, that adjusted SDG&E’s rate of return to 7.45%.

The GRC FD adopts a 2024 revenue requirement of $3,806 million for SoCalGas. SoCalGas’ authorized 2024 revenue requirement represents an increase of $324 million (9.3%) over its authorized 2023 revenue requirement. In connection with SoCalGas’ election to change its tax accounting method for gas repairs expenditures, the 2024 revenue requirement increase is net of $202 million of income tax benefits for 2023 and 2024 to be flowed through to customers. The GRC FD also specifies an increase in SoCalGas’ 2025, 2026, and 2027 revenue requirements of $190 million (5.00%), $116 million (2.91%) and $120 million (2.92%), respectively, over the preceding year’s revenue requirement. The 2025, 2026 and 2027 revenue requirements will be updated to implement a previously authorized change in the cost of capital, which we describe below, that adjusted SoCalGas’ rate of return to 7.49%.

The GRC provides SDG&E and SoCalGas with numerous mechanisms to seek cost recovery of specified projects and programs. We expect that the requests for cost recovery of these projects and programs, which remain subject to CPUC approval, will result in additional amounts of authorized revenue requirement that are not included in the amounts described above.

Since the GRC FD is effective retroactive to January 1, 2024, SDG&E and SoCalGas recorded the retroactive impacts in the fourth quarter of 2024.

2024 Form 10-K | F-58

2024 GRC Track 2

In October 2023, SDG&E submitted a separate request to the CPUC in its 2024 GRC, known as a Track 2 request. This request seeks review and recovery of $1.5 billion of wildfire mitigation plan costs incurred from 2019 through 2022 that were in addition to amounts authorized in the 2019 GRC and not addressed in the 2024 GRC FD. SDG&E expects to receive a proposed decision for its Track 2 request in the first half of 2025.

Revenue requirements associated with the Track 2 request have been recorded in a regulatory account. In February 2024, the CPUC approved an interim cost recovery mechanism that permits SDG&E to recover in rates $194 million and $96 million of this regulatory account balance in 2024 and 2025, respectively. Such recovery of SDG&E’s wildfire mitigation plan regulatory account balance will be subject to refund, contingent on the reasonableness review decision for its Track 2 request.

2024 GRC Track 3

SDG&E expects to submit in the first half of 2025 an additional request to the CPUC in its 2024 GRC, known as a Track 3 request, for review and recovery of wildfire mitigation plan costs incurred in 2023. The GRC FD expanded the scope of the Track 3 filing to include review of SoCalGas’ and SDG&E’s Pipeline Safety Enhancement Plan costs incurred from 2015 to 2020, inclusively.

CPUC COST OF CAPITAL

A CPUC cost of capital proceeding every three years determines a utility’s authorized capital structure and authorized return on rate base. The CCM applies in the interim years and considers changes in the cost of capital based on changes in interest rates based on the applicable utility bond index published by Moody’s (CCM benchmark rate) for each 12-month period ending September 30 (the measurement period). The index applicable to SDG&E and SoCalGas is based on each utility’s credit rating. The CCM benchmark rate is the basis of comparison to determine if the CCM is triggered in each measurement period, which occurs if the change in the applicable Moody’s utility bond index relative to the CCM benchmark rate is larger than plus or minus 1.00% for the measurement period. Alternatively, each of SDG&E and SoCalGas is permitted to file a cost of capital application to have its cost of capital determined in lieu of the CCM in an interim year in which an extraordinary or catastrophic event materially impacts its cost of capital and affects utilities differently than the market as a whole.

The CPUC-approved cost of capital for SDG&E and SoCalGas that became effective on January 1, 2020 remained in effect through December 31, 2022. The CPUC subsequently approved the cost of capital for SDG&E and SoCalGas that became effective on January 1, 2023 and was to remain in effect through December 31, 2025, subject to the CCM. The CCM was triggered for SDG&E and SoCalGas for the measurement period ending September 30, 2023, and in December 2023, the CPUC approved updated authorized rates of return effective January 1, 2024.

In October 2023, the CPUC issued a ruling to initiate a second phase of the 2023-2025 cost of capital proceeding to evaluate potential modifications to the CCM. In October 2024, the CPUC issued an FD to modify the CCM. The FD updates the upward or downward adjustment to authorized ROE, if the CCM is triggered, from 50% to 20% of the change in the benchmark rate during the measurement period. The FD adopted this change effective January 1, 2025, reducing both SDG&E’s and SoCalGas’ ROE by 42 bps to 10.23% and 10.08%, respectively, and allowing SDG&E and SoCalGas to update their respective costs of preferred equity and debt for 2025.

2024 Form 10-K | F-59

The following table summarizes the cost of capital for SDG&E and SoCalGas. The authorized weighting remained unchanged for each of the years presented.

AUTHORIZED COST OF CAPITAL
	Authorized weighting		2022		2023		2024		2025		2022		2023(1)		2024		2025
			Return on rate base								Weighted return on rate base
SDG&E:
Long-Term Debt	45.25	%	4.59	%	4.05	%	4.34	%	4.34	%	2.08	%	1.83	%	1.96	%	1.96	%
Preferred Equity	2.75		6.22		6.22		6.22		6.22		0.17		0.17		0.17		0.17
Common Equity	52.00		10.20		9.95		10.65		10.23		5.30		5.17		5.54		5.32
	100.00	%									7.55	%	7.18	%	7.67	%	7.45	%
SoCalGas:
Long-Term Debt	45.60	%	4.23	%	4.07	%	4.54	%	4.63	%	1.93	%	1.86	%	2.07	%	2.11	%
Preferred Equity	2.40		6.00		6.00		6.00		6.00		0.14		0.14		0.14		0.14
Common Equity	52.00		10.05		9.80		10.50		10.08		5.23		5.10		5.46		5.24
	100.00	%									7.30	%	7.10	%	7.67	%	7.49	%

(1)    Total weighted return on rate base for SDG&E does not sum due to rounding differences.

FERC RATE MATTERS

SDG&E files separately with the FERC for its authorized transmission revenue requirement and ROE on FERC-regulated electric transmission operations and assets.

TO5 Settlement

SDG&E’s authorized TO5 settlement provided for an ROE of 10.60%, consisting of a base ROE of 10.10% plus the California ISO adder. In December 2024, the FERC issued an order, which SDG&E has appealed, finding that SDG&E is not eligible for the California ISO adder and that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019. As a result of the FERC order, SDG&E recorded a charge of $120 million ($89 million after tax) with $94 million in Electric Revenues and $26 million in Other Income, Net, on the SDG&E and Sempra Consolidated Statements of Operations in the year ended December 31, 2024.

TO6 Filing

In June 2024, SDG&E exercised its right to terminate the TO5 settlement. Accordingly, in October 2024, SDG&E submitted its TO6 filing to the FERC, requested to be effective January 1, 2025, and subject to refund. SDG&E’s TO6 filing proposes, among other items, an increase to SDG&E’s currently authorized base ROE from 10.10% to 11.75% plus the California ISO adder, for a total ROE of 12.25%. In December 2024, the FERC accepted SDG&E’s TO6 filing but suspended the effective date to June 1, 2025 and disallowed the inclusion of the California ISO adder, which SDG&E has appealed.

NOTE 5. SEMPRA – INVESTMENTS IN UNCONSOLIDATED ENTITIES

We generally account for investments under the equity method when we have significant influence over, but do not have control of, these entities. Equity earnings and losses, both before and net of income tax, are combined and presented as Equity Earnings on the Consolidated Statements of Operations. Distributions received from equity method investees are classified in the Consolidated Statements of Cash Flows as either a return on investment in operating activities or a return of investment in investing activities based on the “nature of the distribution” approach.

Our equity method investments include various domestic and foreign entities. Our domestic equity method investees are typically partnerships that are pass-through entities for income tax purposes and therefore they do not record income tax. Sempra’s income tax on earnings from these equity method investees, other than Oncor Holdings as we discuss below, is included in Income Tax Expense on the Consolidated Statements of Operations. Our foreign equity method investees are generally corporations whose operations are taxable on a standalone basis in the countries in which they operate, and we recognize our equity in such income or loss net of investee income tax. See Note 7 for information on how equity earnings and losses before income taxes are factored into the calculations of our pretax income or loss and ETR.

2024 Form 10-K | F-60

We provide the carrying values of our investments and earnings on these investments by segment in the following tables.

EQUITY METHOD AND OTHER INVESTMENTS(1)
(Dollars in millions)
	Percent ownership				Investment balance
	December 31,
	2024		2023		2024		2023
Sempra Texas Utilities:
Oncor Holdings(2)	100	%	100	%	$	15,400	$	14,266
Sempra Texas Utilities:
Sharyland Holdings(3)	50	%	50	%	$	122	$	114
Sempra Infrastructure:
Cameron LNG JV(4)	50.2		50.2		1,149		1,008
IMG(5)	40		40		723		620
TAG Norte(6)	50		50		539		501
Segment totals					2,533		2,243
Parent and other – Other					1		1
Total					$	2,534	$	2,244

(1)    All amounts are before NCI, where applicable.

(2)    The carrying value of our equity method investment is $2,884 and $2,870 higher than the underlying equity in the net assets of the investee at December 31, 2024 and 2023, respectively, due to $2,868 of equity method goodwill and $69 in basis differences in AOCI, offset by $53 and $67 at December 31, 2024 and 2023, respectively, due to a tax sharing liability to TTI under a tax sharing agreement.

(3)    The carrying value of our equity method investment is $41 higher than the underlying equity in the net assets of the investee due to equity method goodwill.

(4)    The carrying value of our equity method investment is $257 and $262 higher than the underlying equity in the net assets of the investee at December 31, 2024 and 2023, respectively, primarily due to guarantees, interest capitalized on the investment prior to the JV commencing its operations, and amortization of guarantee fees and capitalized interest thereafter.

(5)    The carrying value of our equity method investment is $5 higher than the underlying equity in the net assets of the investee due to guarantees.

(6)    The carrying value of our equity method investment is $130 higher than the underlying equity in the net assets of the investee due to equity method goodwill.

EARNINGS FROM EQUITY METHOD INVESTMENTS(1)
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
EARNINGS RECORDED BEFORE INCOME TAX(2):
Sempra Texas Utilities:
Sharyland Holdings	$	8	$	7	$	7
Sempra Infrastructure:
Cameron LNG JV(3)	576		586		659
Segment totals	584		593		666
Parent and other – RBS Sempra Commodities LLP	19		40		—
	603		633		666
EARNINGS RECORDED NET OF INCOME TAX:
Sempra Texas Utilities:
Oncor Holdings	780		694		735
Sempra Infrastructure:
IMG	136		40		68
TAG Norte	90		114		29
Segment totals	1,006		848		832
Total	$	1,609	$	1,481	$	1,498

(1)    All amounts are before NCI, where applicable.

(2)    We provide our ETR calculation in Note 7.

(3)    Includes $9 and $12 of basis differences in equity earnings related to AOCI in 2023 and 2022, respectively.

2024 Form 10-K | F-61

We provide the contributions to and distributions from our investments by segment in the following tables.

EXPENDITURES FOR INVESTMENTS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra Texas Utilities:
Oncor Holdings	$	972	$	363	$	341
Sharyland Holdings	4		4		5
	976		367		346
Sempra Infrastructure:
Cameron LNG JV	12		15		30
	12		15		30
Total	$	988	$	382	$	376

DISTRIBUTIONS FROM INVESTMENTS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra Texas Utilities:
Oncor Holdings(1)	$	616	$	441	$	340
Sharyland Holdings	4		4		5
	620		445		345
Sempra Infrastructure:
Cameron LNG JV	453		456		509
IMG	33		11		—
TAG Norte	62		36		32
	548		503		541
Segment totals	1,168		948		886
Parent and other – RBS Sempra Commodities LLP	9		—		—
Total	$	1,177	$	948	$	886

(1)    Includes a $13 noncash return on investment in 2024. When including payments received under a tax sharing agreement, cash and noncash distributions would total $681, $558 and $443 in 2024, 2023 and 2022, respectively.

At December 31, 2024 and 2023, our share of the undistributed earnings of equity method investments was $2.9 billion and $2.5 billion, respectively, including $630 million at December 31, 2024 in undistributed earnings from investments for which we have less than 50% equity interests.

ONCOR HOLDINGS

We account for our 100% equity ownership interest in Oncor Holdings, which owns an 80.25% interest in Oncor, as an equity method investment. Sempra does not control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and commitments in effect limit our ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends, strategic planning and other important corporate issues and actions. We also have limited representation on the Oncor Holdings and Oncor boards of directors.

Oncor is a domestic partnership for U.S. federal income tax purposes and is not included in the consolidated income tax return of Sempra. Rather, only our pretax equity earnings from our investment in Oncor Holdings (a disregarded entity for tax purposes) are included in our consolidated income tax return. A tax sharing agreement with TTI, Oncor Holdings and Oncor provides for the calculation of an income tax liability substantially as if Oncor Holdings and Oncor were taxed as corporations and requires tax payments determined on that basis. While partnerships are not subject to income taxes, in consideration of the tax sharing agreement and Oncor being subject to the provisions of U.S. GAAP governing rate-regulated operations, Oncor recognizes amounts determined under cost-based regulatory rate-setting processes (with such costs including income taxes), as if it were taxed as a corporation. As a result, since Oncor Holdings consolidates Oncor, we recognize equity earnings from our investment in Oncor Holdings net of its recorded income tax.

2024 Form 10-K | F-62

We provide summarized income statement and balance sheet information for Oncor Holdings in the following table.

SUMMARIZED FINANCIAL INFORMATION – ONCOR HOLDINGS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Operating revenues	$	6,082	$	5,586	$	5,243
Operating expenses	(4,318)		(4,026)		(3,682)
Income from operations	1,764		1,560		1,561
Interest expense	(653)		(536)		(445)
Income tax expense	(217)		(192)		(203)
Net income	957		849		893
NCI held by TTI	(192)		(170)		(179)
Earnings attributable to Sempra (1)	765		679		714
			December 31,
			2024		2023
Current assets			$	1,638	$	1,431
Noncurrent assets			38,697		34,649
Current liabilities			2,183		1,625
Noncurrent liabilities			21,958		19,727
NCI held by TTI			3,689		3,338

(1)    Excludes adjustments to equity earnings related to amortization of a tax sharing liability associated with a tax sharing agreement and changes in basis differences in AOCI within the carrying value of our equity method investment.

SHARYLAND HOLDINGS

We account for our 50% ownership interest in Sharyland Holdings, a JV with SU Investment Partners, L.P. that owns a 100% interest in Sharyland Utilities, as an equity method investment.

CAMERON LNG JV

Cameron LNG JV is a JV between Sempra and three project partners, TotalEnergies SE, Mitsui & Co., Ltd., and Japan LNG Investment, LLC, a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha. We account for SI Partners’ 50.2% investment in Cameron LNG JV under the equity method.

Sempra Promissory Note for SDSRA Distribution

Cameron LNG JV’s debt agreements require Cameron LNG JV to maintain the SDSRA, which is an additional reserve account beyond the Senior Debt Service Accrual Account, where funds accumulate from operations to satisfy senior debt obligations due and payable on the next payment date. Both accounts can be funded with cash or authorized investments. In June 2021, Sempra Infrastructure received a distribution of $165 million based on its proportionate share of the SDSRA, for which Sempra provided a promissory note and letters of credit to secure a proportionate share of Cameron LNG JV’s obligation to fund the SDSRA. Sempra’s maximum exposure to loss is replenishment of the amount withdrawn by Sempra Infrastructure from the SDSRA, or $165 million. We recorded a guarantee liability of $22 million in June 2021, with an associated carrying value of $18 million at December 31, 2024, for the fair value of the promissory note, which is being reduced over the duration of the guarantee through Sempra Infrastructure’s investment in Cameron LNG JV. The guarantee will terminate upon full repayment of Cameron LNG JV’s debt, scheduled to occur in 2039, or replenishment of the amount withdrawn by Sempra Infrastructure from the SDSRA.

Sempra Support Agreement for CFIN

In July 2020, CFIN entered into a financing arrangement with Cameron LNG JV’s four project owners and received aggregate proceeds of $1.5 billion from two project owners and from external lenders on behalf of the other two project owners (collectively, the affiliate loans), based on their proportionate ownership interest in Cameron LNG JV. CFIN used the proceeds from the affiliate loans to provide a loan to Cameron LNG JV. The affiliate loans mature in 2039. Principal and interest are paid from Cameron LNG JV’s project cash flows from its three-train natural gas liquefaction facility. Cameron LNG JV used the proceeds from its loan to return equity to its project owners.

2024 Form 10-K | F-63

Sempra Infrastructure’s $753 million proportionate share of the affiliate loans, based on SI Partners’ 50.2% ownership interest in Cameron LNG JV, was funded by external lenders comprised of a syndicate of eight banks (the bank debt) to whom Sempra has provided a guarantee pursuant to a Support Agreement under which:

▪Sempra has severally guaranteed repayment of the bank debt plus accrued and unpaid interest if CFIN fails to pay the external lenders;

▪the external lenders may exercise an option to put the bank debt to Sempra Infrastructure upon the occurrence of certain events, including a failure by CFIN to meet its payment obligations under the bank debt;

▪the external lenders will put some or all of the bank debt to Sempra Infrastructure on the fifth, tenth, or fifteenth anniversary date of the affiliate loans, except the portion of the debt owed to any external lender that has elected not to participate in the put option three months prior to the respective anniversary date;

▪Sempra Infrastructure also has a right to call the bank debt back from, or to refinance the bank debt with, the external lenders at any time; and

▪the Support Agreement will terminate upon full repayment of the bank debt, including repayment following an event in which the bank debt is put to Sempra Infrastructure.

In exchange for this guarantee, the external lenders pay a guarantee fee that is based on the credit rating of Sempra’s long-term senior unsecured non-credit enhanced debt rating, which guarantee fee Sempra Infrastructure recognizes as interest income as earned. Sempra’s maximum exposure to loss is the bank debt plus any accrued and unpaid interest and related fees, subject to a liability cap of 130% of the bank debt, or $979 million. We measure the Support Agreement at fair value, net of related guarantee fees, on a recurring basis (see Note 10). At December 31, 2024, the fair value of the Support Agreement was $25 million, of which $7 million is included in Other Current Assets and $18 million is included in Other Long-Term Assets on Sempra’s Consolidated Balance Sheet.

IMG

SI Partners’ has a 40% interest in IMG, a JV with a subsidiary of TC Energy Corporation, and accounts for its interest as an equity method investment. IMG owns and operates the Sur de Texas-Tuxpan natural gas marine pipeline, which is fully contracted under a 35-year natural gas transportation service contract with the CFE.

TAG NORTE

SI Partners’ has a 50% beneficial ownership interest in TAG Norte, a JV with TETL JV Mexico Norte, S. de R.L. de C.V. and Bravo N Mergeco, S. de R.L. de C.V. that owns a 50% interest in the Los Ramones Norte pipeline. SI Partners accounts for its 50% interest in TAG Norte as an equity method investment.

RBS SEMPRA COMMODITIES LLP

RBS Sempra Commodities LLP is a United Kingdom limited liability partnership formed by Sempra and The Royal Bank of Scotland plc (RBS) in 2008 to own and operate the commodities-marketing businesses previously operated through wholly owned subsidiaries of Sempra. We and RBS sold substantially all of the partnership’s businesses and assets in four separate transactions completed in 2010 and 2011. Since 2011, our investment balance has reflected our share of the remaining partnership assets, including amounts retained by the partnership to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership and the distribution of the partnership’s remaining assets, if any. We accounted for our investment in RBS Sempra Commodities LLP under the equity method.

In 2018, we fully impaired our remaining equity method investment in RBS Sempra Commodities LLP. In 2023, we reduced our previously recorded estimate of losses by $40 million based on a settlement that fully resolved legal matters that we discuss in “Legal Proceedings – Other Sempra” in Note 15. In 2024, we substantially completed the dissolution of the partnership, at which time we recorded $19 million ($16 million after tax) in Equity Earnings on Sempra’s Consolidated Statement of Operations.

2024 Form 10-K | F-64

SUMMARIZED FINANCIAL INFORMATION

We present summarized financial information below, aggregated for all other equity method investments (excluding Oncor Holdings and RBS Sempra Commodities LLP) for the periods in which we were invested in the entities. The amounts below represent the results of operations and aggregate financial position of 100% of each of Sempra’s other equity method investments.

SUMMARIZED FINANCIAL INFORMATION – OTHER EQUITY METHOD INVESTMENTS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Gross revenues	$	2,962	$	3,083	$	2,959
Operating expenses	(820)		(776)		(772)
Income from operations	2,142		2,307		2,187
Interest expense	(547)		(570)		(505)
Net income/Earnings(1)(2)	1,688		1,499		1,537

	December 31,
	2024		2023
Current assets	$	1,134	$	1,216
Noncurrent assets	14,687		14,826
Current liabilities	1,130		1,255
Noncurrent liabilities	10,051		10,786

(1)    Except for our investments in Mexico, there was no income tax recorded by the entities, as they are primarily domestic partnerships.

(2)    Amounts for Cameron LNG JV exclude adjustments to equity earnings related to amortization of capitalized interest and guarantee fees within the carrying value of our equity method investment and changes in basis differences in equity earnings related to AOCI.

NOTE 6. DEBT AND CREDIT FACILITIES

SHORT-TERM DEBT

Committed Lines of Credit

At December 31, 2024, Sempra had an aggregate capacity of $9.9 billion under seven primary committed lines of credit, which provide liquidity and support our commercial paper programs. Because our commercial paper programs are supported by some of these lines of credit, we reflect the amount of commercial paper outstanding, before reductions of any unamortized discounts, and any letters of credit outstanding as a reduction to the available unused credit capacity in the following table.

COMMITTED LINES OF CREDIT
(Dollars in millions)
		December 31, 2024
Borrower	Expiration date of facility	Total facility		Commercial paper outstanding		Amounts outstanding		Letters of credit outstanding		Available unused credit
Sempra	October 2029	$	4,000	$	—	$	—	$	—	$	4,000
SDG&E	October 2029	1,500		(417)		—		—		1,083
SoCalGas	October 2029	1,200		(337)		—		—		863
SI Partners and IEnova	September 2025	500		—		(368)		—		132
SI Partners and IEnova	August 2026	1,000		—		—		—		1,000
SI Partners and IEnova	August 2028	1,500		—		(186)		—		1,314
Port Arthur LNG	March 2030	200		—		—		(64)		136
Total		$	9,900	$	(754)	$	(554)	$	(64)	$	8,528

2024 Form 10-K | F-65

The principal terms of Sempra’s, SDG&E’s and SoCalGas’ lines of credit reflected in the table above include the following:

▪Each facility has a syndicate of 23 lenders. No single lender has greater than a 6% share in any facility.

▪Sempra’s, SDG&E’s and SoCalGas’ facilities provide for the issuance of $200 million, $100 million and $150 million, respectively, of letters of credit. Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, Sempra, SDG&E and SoCalGas each has the right to increase its letter of credit commitment to up to $500 million, $250 million and $250 million, respectively.

▪Borrowings bear interest at a benchmark rate plus a margin that varies with the borrower’s credit rating.

▪Each borrower must maintain a ratio of indebtedness to total capitalization (as defined in each of the applicable credit facilities) of no more than 65% at the end of each quarter. At December 31, 2024, each Registrant was in compliance with this ratio under its respective credit facility.

SI Partners and IEnova have three combined lines of credit, reflected in the table above, that require borrowings to be issued in U.S. dollars only and include the following principal terms:

▪Borrowings on the $500 million revolving credit facility bear interest at a per annum rate equal to term SOFR plus 80 bps (including a credit adjustment spread).

▪The $1.0 billion facility provides for borrowings of up to $1.0 billion through a syndicate of 12 lenders available to SI Partners and up to $910 million through a syndicate of 11 lenders available to IEnova, subject to a combined borrowing limit of $1.0 billion. This facility:

◦Charges interest on borrowings at a benchmark rate plus a margin that varies with SI Partners’ credit rating (plus a term SOFR credit adjustment spread of 10 bps in all tenors).

◦Provides for issuance of up to $200 million of letters of credit, subject to a combined letter of credit commitment of $200 million, which can be issued in U.S. dollars or Mexican pesos, and which reduces available unused credit.

◦Includes a $100 million swingline loan sub-limit, whereby any outstanding amounts would reduce available unused credit. No swingline loan borrowings were outstanding at December 31, 2024.

◦Gives either SI Partners or IEnova the right to increase the total facility to $1.5 billion, subject to lender approval, with borrowings of up to $1.5 billion through a syndicate of 12 lenders available to SI Partners and up to $1,365 million through a syndicate of 11 lenders available to IEnova.

▪Borrowings on the $1.5 billion revolving credit facility, with borrowings of up to $1.5 billion through a syndicate of 12 lenders available to SI Partners and up to $1,365 million through a syndicate of 11 lenders available to IEnova, subject to a combined borrowing limit of $1.5 billion, bear interest at a per annum rate equal to term SOFR plus 90 bps (including a credit adjustment spread).

Additionally, the three lines of credit that are shared by SI Partners and IEnova require that SI Partners maintain a ratio of consolidated adjusted net indebtedness to consolidated earnings before interest, taxes, depreciation and amortization (as defined in each credit facility) of no more than 5.25 to 1.00 at the end of each quarter. At December 31, 2024, SI Partners was in compliance with this ratio.

Port Arthur LNG has a working capital facility agreement, reflected in the table above, that permits borrowings of up to $200 million, which bear interest by reference to term SOFR plus the applicable margin and a credit adjustment spread. The credit facility also provides for the issuance of up to $200 million of letters of credit, which reduces available unused credit.

Uncommitted Line of Credit

ECA LNG Phase 1 has an uncommitted line of credit with an aggregate capacity of $100 million that expires in August 2026. Borrowings are generally used for working capital requirements and can be in U.S. dollars or Mexican pesos. At December 31, 2024, ECA LNG Phase 1 had outstanding borrowings of $8 million, before reductions of any unamortized discounts, in Mexican pesos that bear interest at a variable rate based on the 28-day Interbank Equilibrium Interest Rate plus 154 bps. Borrowings made in U.S. dollars bear interest at a variable rate based on the one-month or three-month SOFR plus 164 bps and a credit adjustment spread of 10 bps.

2024 Form 10-K | F-66

Uncommitted Letters of Credit

Outside of our domestic and foreign credit facilities, we have bilateral unsecured standby letter of credit capacity with select lenders that is uncommitted and supported by reimbursement agreements. At December 31, 2024, we had $497 million in standby letters of credit outstanding under these agreements.

UNCOMMITTED LETTERS OF CREDIT OUTSTANDING
(Dollars in millions)
	Expiration date range	December 31, 2024
SDG&E	January 2025 - November 2025	$	26
SoCalGas	January 2025 - December 2025	20
Other Sempra	January 2025 - November 2054	451
Total Sempra		$	497

Term Loan

In May 2024, SoCalGas entered into a $500 million, 364-day term loan facility with a maturity date of May 22, 2025, and in December 2024, SoCalGas increased the amount of the term loan to $700 million. At December 31, 2024, SoCalGas had borrowed the full $700 million then available under the term loan, net of negligible debt issuance costs, which is included in Short-Term Debt on SoCalGas’ Balance Sheet. SoCalGas may request a further increase in the term loan facility of up to $300 million prior to the maturity date, subject to lender approval. The outstanding borrowings bear interest at a per annum rate equal to term SOFR, plus 80 bps and a credit adjustment spread of 10 bps. SoCalGas used the proceeds to repay commercial paper and for other general corporate purposes.

Weighted-Average Interest Rates

The weighted-average interest rates on all short-term debt were as follows:

WEIGHTED-AVERAGE INTEREST RATES
	December 31,
	2024		2023
Sempra	5.03	%	5.96	%
SDG&E	4.76		—
SoCalGas	5.02		5.44

2024 Form 10-K | F-67

LONG-TERM DEBT

The following tables show the detail and maturities of long-term debt outstanding.

LONG-TERM DEBT AND FINANCE LEASES
(Dollars in millions)
	December 31,
	2024		2023
SDG&E:
First mortgage bonds (collateralized by plant assets):
2.50% May 15, 2026	$	500	$	500
6.00% June 1, 2026	250		250
4.95% August 15, 2028	600		600
1.70% October 1, 2030	800		800
3.00% March 15, 2032	500		500
5.35% May 15, 2035	250		250
6.125% September 15, 2037	250		250
6.00% June 1, 2039	300		300
5.35% May 15, 2040	250		250
4.50% August 15, 2040	500		500
3.95% November 15, 2041	250		250
4.30% April 1, 2042	250		250
3.75% June 1, 2047	400		400
4.15% May 15, 2048	400		400
4.10% June 15, 2049	400		400
3.32% April 15, 2050	400		400
2.95% August 15, 2051	750		750
3.70% March 15, 2052	500		500
5.35% April 1, 2053	800		800
5.55% April 15, 2054	600		—
	8,950		8,350
Other long-term debt (uncollateralized):
Notes at variable rates (5.99% at December 31, 2023) February 18, 2024(1)	—		400
Finance lease obligations:
Power purchase agreements	1,138		1,166
Other	67		67
	1,205		1,633
	10,155		9,983
Current portion of long-term debt and finance leases	(42)		(441)
Unamortized discount on long-term debt	(33)		(29)
Unamortized debt issuance costs	(62)		(60)
Total SDG&E	$	10,018	$	9,453

(1)    Callable long-term debt not subject to make-whole provisions.

2024 Form 10-K | F-68

LONG-TERM DEBT AND FINANCE LEASES (CONTINUED)
(Dollars in millions)
	December 31,
	2024		2023
SoCalGas:
First mortgage bonds (collateralized by plant assets):
3.15% September 15, 2024	$	—	$	500
3.20% June 15, 2025	350		350
2.60% June 15, 2026	500		500
2.55% February 1, 2030	650		650
5.20% June 1, 2033	500		500
5.05% September 1, 2034	600		—
5.75% November 15, 2035	250		250
5.125% November 15, 2040	300		300
3.75% September 15, 2042	350		350
4.45% March 15, 2044	250		250
4.125% June 1, 2048	400		400
4.30% January 15, 2049	550		550
3.95% February 15, 2050	350		350
6.35% November 15, 2052	600		600
5.75% June 1, 2053	500		500
5.60% April 1, 2054	500		—
	6,650		6,050
Other long-term debt (uncollateralized):
1.875% Notes May 14, 2026(1)	4		4
2.95% Notes April 15, 2027	700		700
5.67% Notes January 18, 2028(2)	5		5
Finance lease obligations	110		107
	819		816
	7,469		6,866
Current portion of long-term debt and finance leases	(373)		(523)
Unamortized discount on long-term debt	(18)		(13)
Unamortized debt issuance costs	(47)		(42)
Total SoCalGas	$	7,031	$	6,288

(1)    Callable long-term debt not subject to make-whole provisions.

(2)    Debt is not callable.

2024 Form 10-K | F-69

LONG-TERM DEBT AND FINANCE LEASES (CONTINUED)
(Dollars in millions)
	December 31,
	2024		2023
Other Sempra:
Sempra - Other long-term debt (uncollateralized):
3.30% Notes April 1, 2025	$	750	$	750
5.40% Notes August 1, 2026	550		550
3.25% Notes June 15, 2027	750		750
3.40% Notes February 1, 2028	1,000		1,000
3.70% Notes April 1, 2029	500		500
5.50% Notes August 1, 2033	700		700
3.80% Notes February 1, 2038	1,000		1,000
6.00% Notes October 15, 2039	750		750
4.00% Notes February 1, 2048	800		800
4.125% (next rate reset on April 1, 2027) Junior Subordinated Notes April 1, 2052(1)	1,000		1,000
6.40% (next rate reset on October 1, 2034) Junior Subordinated Notes October 1, 2054(1)	1,250		—
6.875% (next rate reset on October 1, 2029) Junior Subordinated Notes October 1, 2054(1)	600		—
6.875% (next rate reset on October 1, 2029) Junior Subordinated Notes October 1, 2054(1)	500		—
6.55% (next rate reset on April 1, 2035) Junior Subordinated Notes April 1, 2055(1)	600		—
6.625% (next rate reset on April 1, 2030) Junior Subordinated Notes April 1, 2055(1)	400		—
5.75% Junior Subordinated Notes July 1, 2079(1)	758		758
	11,908		8,558
Sempra Infrastructure - Other long-term debt (uncollateralized unless otherwise noted):
Loan at variable rates (weighted-average rate of 7.29% and 8.31% at December 31, 2024 and 2023, respectively) December 9, 2025	1,063		832
3.75% Notes January 14, 2028	300		300
Loan at variable rates (includes $1,090 and $200 at December 31, 2024 and 2023, respectively, (5.329% after floating-to-fixed rate swaps effective 2023) and $58 at December 31, 2023 (weighted-average rate of 7.37% at December 31, 2023)) March 20, 2030, collateralized by plant assets(1)	1,090		258
3.25% Notes January 15, 2032	400		400
Loan at variable rates (4.03% after floating-to-fixed rate swap effective 2019) payable June 15, 2022 through November 19, 2034(1)	90		96
Loan at variable rates (4.03% after floating-to-fixed rate swap effective 2019) payable June 15, 2022 through November 19, 2034(1)	90		96
Loan at variable rates (2.38% after floating-to-fixed rate swap effective 2020) payable June 15, 2022 through November 19, 2034(1)	90		96
2.90% Loan payable June 15, 2022 through November 19, 2034(1)	219		231
4.875% Notes January 14, 2048	540		540
4.75% Notes January 15, 2051	800		800
	4,682		3,649
	16,590		12,207
Current portion of long-term debt	(1,859)		(11)
Unamortized discount on long-term debt	(78)		(66)
Unamortized debt issuance costs	(144)		(112)
Total Other Sempra	14,509		12,018
Total Sempra	$	31,558	$	27,759

(1)    Callable long-term debt not subject to make-whole provisions.

2024 Form 10-K | F-70

At December 31, 2024, scheduled maturities of long-term debt are as follows:

MATURITIES OF LONG-TERM DEBT(1)
(Dollars in millions)
	SDG&E		SoCalGas		Other Sempra		Total Sempra
2025	$	—	$	350	$	1,862	$	2,212
2026	750		504		599		1,853
2027	—		700		799		1,499
2028	600		5		1,358		1,963
2029	—		—		584		584
Thereafter	7,600		5,800		11,388		24,788
Total	$	8,950	$	7,359	$	16,590	$	32,899

(1)    Excludes finance lease obligations, discounts, and debt issuance costs.

Various long-term obligations totaling $16.2 billion at Sempra at December 31, 2024 are unsecured. This includes unsecured long-term obligations totaling $709 million at SoCalGas.

Callable Long-Term Debt

At the option of Sempra, SDG&E and SoCalGas, certain debt at December 31, 2024 is callable subject to premiums:

CALLABLE LONG-TERM DEBT
(Dollars in millions)
	SDG&E		SoCalGas		Other Sempra		Total Sempra
Not subject to make-whole provisions	$	—	$	4	$	6,687	$	6,691
Subject to make-whole provisions	8,950		7,350		9,903		26,203

First Mortgage Bonds

SDG&E and SoCalGas issue first mortgage bonds secured by liens on their respective utility plant assets. SDG&E and SoCalGas may issue additional first mortgage bonds if in compliance with the provisions of their bond agreements (indentures). These indentures require, among other things, the satisfaction of pro forma earnings-coverage tests on first mortgage bond interest and the availability of sufficient mortgaged property to support the additional bonds, after giving effect to prior bond redemptions. The most restrictive of these tests (the property test) would permit the issuance, subject to CPUC authorization, of additional first mortgage bonds of $8.8 billion at SDG&E and $1.6 billion at SoCalGas at December 31, 2024.

SDG&E

In March 2024, SDG&E issued $600 million aggregate principal amount of 5.55% first mortgage bonds due in full upon maturity on April 15, 2054 and received proceeds of $587 million (net of debt discount, underwriting discounts and debt issuance costs of $13 million). The first mortgage bonds are redeemable prior to maturity, subject to their terms, and in certain circumstances subject to make-whole provisions. SDG&E used the net proceeds to repay commercial paper and for other general corporate purposes.

SoCalGas

In March 2024, SoCalGas issued $500 million aggregate principal amount of 5.60% first mortgage bonds due in full upon maturity on April 1, 2054 and received proceeds of $491 million (net of debt discount, underwriting discounts and debt issuance costs of $9 million). The first mortgage bonds are redeemable prior to maturity, subject to their terms, and in certain circumstances subject to make-whole provisions. SoCalGas used the net proceeds to repay outstanding indebtedness and for other general corporate purposes.

In August 2024, SoCalGas issued $600 million aggregate principal amount of 5.05% first mortgage bonds due in full upon maturity on September 1, 2034 and received proceeds of $592 million (net of debt discount, underwriting discounts and debt issuance costs of $8 million). The first mortgage bonds are redeemable prior to maturity, subject to their terms, and in certain circumstances subject to make-whole provisions. SoCalGas used the net proceeds to repay outstanding indebtedness and for other general corporate purposes.

2024 Form 10-K | F-71

Other Long-Term Debt

Other Sempra

Sempra. Sempra issued the following fixed-to-fixed reset rate junior subordinated notes in 2024:

▪In March 2024, Sempra issued $600 million aggregate principal amount of 6.875% junior subordinated notes maturing on October 1, 2054, and received proceeds of $593 million (net of debt discount, underwriting discounts and debt issuance costs of $7 million). In May 2024, Sempra issued an additional $500 million aggregate principal amount of these junior subordinated notes and received proceeds of $489 million (net of debt discount, underwriting discounts and debt issuance costs of $11 million, but excluding $7 million paid to us in respect of accrued interest from and including March 14, 2024 to, but excluding, May 31, 2024. Interest accrues from and including March 14, 2024 to, but excluding, October 1, 2029 at the rate of 6.875% per annum.

▪In September 2024, Sempra issued $1.25 billion aggregate principal amount of 6.40% junior subordinated notes maturing on October 1, 2054, and received proceeds of $1.235 billion (net of underwriting discounts and debt issuance costs of $15 million). Interest accrues from and including September 9, 2024 to, but excluding, October 1, 2034 at the rate of 6.40% per annum.

▪In November 2024, Sempra issued $400 million aggregate principal amount of 6.625% junior subordinated notes maturing on April 1, 2055, and received proceeds of $395 million (net of underwriting discounts and debt issuance costs of $5 million). Interest accrues from and including November 21, 2024 to, but excluding, April 1, 2030 at the rate of 6.625% per annum.

▪In November 2024, Sempra issued $600 million aggregate principal amount of 6.55% junior subordinated notes maturing on April 1, 2055, and received proceeds of $593 million (net of underwriting discounts and debt issuance costs of $7 million). Interest accrues from and including November 21, 2024 to, but excluding, April 1, 2035 at the rate of 6.55% per annum.

The interest rates on the notes will be reset on:

▪October 1, 2029 (for the March 2024 and May 2024 issuances),

▪October 1, 2034 (for the September 2024 issuance),

▪April 1, 2030 (for the $400 million November 2024 issuance), and

▪April 1, 2035 (for the $600 million November 2024 issuance),

and on each subsequent five-year period beginning on October 1 or April 1, as applicable, of every fifth year thereafter, at a rate per annum equal to the Five-year U.S. Treasury Rate (as defined in the notes) as of the day falling two business days before the first day of such five-year period plus a spread of:

▪2.789% (for the March 2024 and May 2024 issuances),

▪2.632% (for the September 2024 issuance),

▪2.354% (for the $400 million November 2024 issuance), and

▪2.138% (for the $600 million November 2024 issuance).

Interest is payable on the notes semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2024 (for the March 2024 and May 2024 issuances) or April 1, 2025 (for the September 2024 and November 2024 issuances).

We may redeem some or all of the notes before their maturity, as follows:

▪in whole or in part, (i) on any day in the period commencing on the date falling 90 days prior to, and ending on and including October 1, 2029 (for the March 2024 and May 2024 issuances), October 1, 2034 (for the September 2024 issuance), April 1, 2030 (for the $400 million November 2024 issuance), and April 1, 2035 (for the $600 million November 2024 issuance), and (ii) after those respective dates, on any interest payment date, at a redemption price in cash equal to 100% of the principal amount of the notes being redeemed, plus, subject to the terms of the notes, accrued and unpaid interest on the notes to be redeemed to, but excluding, the redemption date;

▪in whole but not in part, at any time following the occurrence and during the continuance of a tax event (as defined in the notes) at a redemption price in cash equal to 100% of the principal amount of the notes, plus, subject to the terms of the notes, accrued and unpaid interest on the notes to, but excluding, the redemption date; and

▪in whole but not in part, at any time following the occurrence and during the continuance of a rating agency event (as defined in the notes) at a redemption price in cash equal to 102% of the principal amount of the notes, plus, subject to the terms of the notes, accrued and unpaid interest on the notes to, but excluding, the redemption date.

2024 Form 10-K | F-72

The notes described above are unsecured obligations and rank junior and subordinate in right of payment to our existing and future senior indebtedness. The notes rank equally in right of payment with each other and with our existing 4.125% fixed-to-fixed reset rate junior subordinated notes due 2052 and 5.75% junior subordinated notes due 2079 and with any future unsecured indebtedness that we may incur if the terms of such indebtedness provide that it ranks equally with the notes in right of payment. The notes are effectively subordinated in right of payment to any secured indebtedness we have incurred or may incur (to the extent of the value of the collateral securing such secured indebtedness) and to all existing and future indebtedness and other liabilities and any preferred equity of our subsidiaries.

We used, or plan to use, the proceeds from the offerings for general corporate purposes, including repayment of commercial paper and other indebtedness.

ECA LNG Phase 1. ECA LNG Phase 1 has a five-year loan agreement with a syndicate of seven external lenders that matures on December 9, 2025 for an aggregate principal amount of up to $1.3 billion. IEnova and TotalEnergies SE have provided guarantees for repayment of the loans plus accrued and unpaid interest of 83.4% and 16.6%, respectively. At December 31, 2024 and 2023, $1.1 billion and $832 million, respectively, of borrowings from external lenders were outstanding under the loan agreement, with a weighted-average interest rate of 7.29% and 8.31%, respectively.

Port Arthur LNG. Port Arthur LNG has a seven-year term loan facility agreement with a syndicate of lenders that matures on March 20, 2030, for an aggregate principal amount of approximately $6.8 billion. At December 31, 2024 and 2023, $1.1 billion and $258 million, respectively, of borrowings were outstanding under the loan agreement, with an all-in weighted-average interest rate of 5.33% and 5.81%, respectively. Proceeds from the loan are being used to finance the cost of construction of the PA LNG Phase 1 project.

In November 2024, Port Arthur LNG signed an agreement to issue senior secured notes in January 2025 for $750 million and April 2025 for $250 million. The net proceeds from the January 2025 issuance and the expected net proceeds from the April 2025 issuance were or will be used to pay transaction fees and repay borrowings under the existing Port Arthur LNG term loan facility. The senior secured notes mature in December 2042 and the January 2025 and April 2025 issuances bear interest at the rate of 6.27% and 6.32% per annum, respectively.

2024 Form 10-K | F-73

NOTE 7. INCOME TAXES

We provide our calculations of ETRs in the following table.

INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Years ended December 31,
	2024			2023			2022
Sempra:
Income tax expense	$	219		$	490		$	556
Income before income taxes and equity earnings	$	2,110		$	2,627		$	1,343
Equity earnings, before income tax(1)	603			633			666
Pretax income	$	2,713		$	3,260		$	2,009
Effective income tax rate	8		%	15		%	28		%
SDG&E:
Income tax expense (benefit)	$	153		$	(26)		$	182
Income before income taxes	$	1,044		$	910		$	1,097
Effective income tax rate	15		%	(3)		%	17		%
SoCalGas:
Income tax expense (benefit)	$	31		$	(5)		$	138
Income before income taxes	$	987		$	807		$	738
Effective income tax rate	3		%	(1)		%	19		%

(1)    We discuss how we recognize equity earnings in Note 5.

For SDG&E and SoCalGas, the CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the ETR. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the ETR. Items subject to flow-through treatment include:

▪repairs expenditures related to certain utility plant fixed assets

▪the equity component of AFUDC, which is non-taxable

▪cost of removal related to certain utility plant assets

▪utility self-developed software expenditures

▪depreciation related to certain utility plant assets

▪state income taxes

AFUDC related to equity recorded for regulated construction projects at Sempra Infrastructure has similar flow-through treatment.

2024 Form 10-K | F-74

We present in the table below reconciliations of net U.S. statutory federal income tax rates to our ETRs.

RECONCILIATION OF FEDERAL INCOME TAX RATES TO EFFECTIVE INCOME TAX RATES
	Years ended December 31,
	2024		2023		2022
Sempra:
U.S. federal statutory income tax rate	21	%	21	%	21	%
Valuation allowances	14		—		(2)
Utility depreciation	4		3		4
Non-U.S. earnings taxed at rates different from the U.S. statutory income tax rate(2)	1		1		3
State income taxes, net of federal income tax benefit	1		1		1
Outside basis differences	—		—		6
Remeasurement of deferred taxes	—		(1)		(3)
Tax credits	(1)		(5)		(1)
Utility self-developed software expenditures	(1)		(1)		—
Allowance for equity funds used during construction	(1)		(1)		(1)
Amortization of excess deferred income taxes	(1)		(1)		(2)
Resolution of prior years’ income tax items	(2)		(2)		(2)
Noncontrolling interests	(3)		(3)		—
Utility repairs expenditures	(8)		(6)		(5)
Foreign exchange and inflation effects(1)	(14)		9		9
Other, net	(2)		—		—
Effective income tax rate	8	%	15	%	28	%
SDG&E:
U.S. federal statutory income tax rate	21	%	21	%	21	%
Depreciation	5		5		3
State income taxes, net of federal income tax benefit	3		2		4
Self-developed software expenditures	(1)		(1)		—
Resolution of prior years’ income tax items	(1)		(1)		(2)
Amortization of excess deferred income taxes	(1)		(2)		(2)
Allowance for equity funds used during construction	(1)		(2)		(2)
Tax credits	(1)		(16)		—
Repairs expenditures	(9)		(8)		(5)
Other, net	—		(1)		—
Effective income tax rate	15	%	(3)	%	17	%
SoCalGas:
U.S. federal statutory income tax rate	21	%	21	%	21	%
Depreciation	5		5		5
Nondeductible expenditures	—		—		2
State income taxes, net of federal income tax benefit	(1)		(2)		2
Amortization of excess deferred income taxes	(1)		(2)		(2)
Allowance for equity funds used during construction	(2)		(1)		(2)
Self-developed software expenditures	(2)		(2)		—
Resolution of prior years’ income tax items	(3)		(6)		—
Repairs expenditures	(14)		(14)		(6)
Other, net	—		—		(1)
Effective income tax rate	3	%	(1)	%	19	%

(1)    Due to fluctuation of the Mexican peso against the U.S. dollar. We record income tax expense (benefit) from the transactional effects of foreign currency and inflation because of appreciation (depreciation) of the Mexican peso.

(2)    Related to operations in Mexico.

We expect to repatriate approximately $3.1 billion of foreign undistributed earnings in the foreseeable future, and have accrued $100 million of U.S. state deferred income tax liability at December 31, 2024. We repatriated approximately $100 million and $108 million to the U.S. in 2024 and 2023, respectively.

2024 Form 10-K | F-75

In the year ended December 31, 2022, we recognized income tax expense of $120 million for a deferred income tax liability related to outside basis differences in our foreign subsidiaries that we had previously considered to be indefinitely reinvested. We have not recorded deferred income taxes with respect to remaining basis differences of approximately $700 million between financial statement and income tax investment amounts in our non-U.S. subsidiaries because we consider them to be indefinitely reinvested as of December 31, 2024. The remaining basis differences are calculated pursuant to U.S. federal tax law, which may differ from tax law in California and foreign jurisdictions. It is currently not practicable to determine the hypothetical amount of tax that might be payable if the underlying basis differences were realized.

The table below presents the geographic location of pretax income.

PRETAX INCOME BY GEOGRAPHIC LOCATION
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra:
U.S.	$	2,354	$	2,678	$	1,449
Non-U.S.	359		582		560
Total(1)	$	2,713	$	3,260	$	2,009

(1)    See the Income Tax Expense (Benefit) and Effective Income Tax Rates table above for the calculation of pretax income.

2024 Form 10-K | F-76

The components of income tax expense are as follows.

INCOME TAX EXPENSE (BENEFIT)
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra:
Current:
U.S. federal	$	73	$	102	$	—
U.S. state	(4)		3		(1)
Non-U.S.	179		208		165
Total	248		313		164
Deferred:
U.S. federal	366		(56)		248
U.S. state	28		18		50
Non-U.S.	(422)		225		94
Total(1)	(28)		187		392
Deferred investment tax credits	(1)		(10)		—
Total income tax expense	$	219	$	490	$	556
SDG&E:
Current:
U.S. federal	$	(16)	$	(156)	$	76
U.S. state	—		(5)		13
Total	(16)		(161)		89
Deferred:
U.S. federal	129		111		54
U.S. state	41		35		38
Total	170		146		92
Deferred investment tax credits	(1)		(11)		1
Total income tax expense (benefit)	$	153	$	(26)	$	182
SoCalGas:
Current:
U.S. federal	$	3	$	(6)	$	(5)
U.S. state	—		(11)		(3)
Total	3		(17)		(8)
Deferred:
U.S. federal	45		22		125
U.S. state	(16)		(11)		22
Total	29		11		147
Deferred investment tax credits	(1)		1		(1)
Total income tax expense (benefit)	$	31	$	(5)	$	138

(1)    In 2024 and 2023, Deferred Income Taxes and Investment Tax Credits on the Sempra Consolidated Statements of Cash Flows also includes $9 and $72, respectively, of income taxes included in equity earnings, which are recorded net of income tax under a tax sharing agreement with Oncor.

2024 Form 10-K | F-77

The tables below present the components of deferred income taxes:

DEFERRED INCOME TAXES
(Dollars in millions)
	December 31,
	2024		2023
Sempra:
Deferred income tax liabilities:
Differences in financial and tax bases of fixed assets, investments and other assets(1)	$	7,164	$	6,875
U.S. state and non-U.S. withholding tax on repatriation of foreign earnings	79		55
Regulatory balancing accounts	850		727
Right-of-use assets – operating leases	325		211
Property taxes	74		68
Postretirement benefits	150		47
Other deferred income tax liabilities	94		68
Total deferred income tax liabilities	8,736		8,051
Deferred income tax assets:
Tax credits	1,485		1,468
Net operating losses	1,105		982
Compensation-related items	225		157
Operating lease liabilities	301		179
Other deferred income tax assets	219		96
Bad debt allowance	151		144
Accrued expenses not yet deductible	80		89
Deferred income tax assets before valuation allowances	3,566		3,115
Less: valuation allowances	503		189
Total deferred income tax assets	3,063		2,926
Net deferred income tax liability(2)	$	5,673	$	5,125

(1)    In addition to the financial over tax basis differences in fixed assets, the amount also includes financial over tax basis differences in various interests in partnerships and certain subsidiaries.

(2)    At December 31, 2024 and 2023, includes $172 and $129, respectively, recorded as a noncurrent asset and $5,845 and $5,254, respectively, recorded as a noncurrent liability on the Consolidated Balance Sheets.

DEFERRED INCOME TAXES
(Dollars in millions)
	SDG&E				SoCalGas
	December 31,
	2024		2023		2024		2023
Deferred income tax liabilities:
Differences in financial and tax bases of utility plant and other assets	$	2,805	$	2,641	$	2,594	$	2,272
Regulatory balancing accounts	545		418		306		309
Right-of-use assets – operating leases	222		103		5		8
Property taxes	47		43		27		25
Postretirement benefits	—		—		124		71
Other deferred income tax liabilities	—		—		2		4
Total deferred income tax liabilities	3,619		3,205		3,058		2,689
Deferred income tax assets:
Tax credits	8		7		2		7
Compensation-related items	8		9		26		31
Operating lease liabilities	222		103		5		8
Bad debt allowance	29		37		72		86
Accrued expenses not yet deductible	10		11		54		56
Net operating losses	122		146		874		890
Other deferred income tax assets	9		19		20		25
Total deferred income tax assets	408		332		1,053		1,103
Net deferred income tax liability	$	3,211	$	2,873	$	2,005	$	1,586

2024 Form 10-K | F-78

The following table summarizes our unused NOLs and tax credit carryforwards.

NET OPERATING LOSSES AND TAX CREDIT CARRYFORWARDS
(Dollars in millions)
	Unused amount at December 31, 2024		Year expiration begins
Sempra:
U.S. federal:
NOLs(1)	$	3,091	2037
General business tax credits(1)	126		2043
Corporate alternative minimum tax credits(1)	676		Indefinite
Foreign tax credits(2)	706		2025
U.S. state:
NOLs(2)	5,912		2027
General business tax credits(1)	24		2027
Non-U.S.(2):
NOLs	782		2025
Foreign tax credits	5		Indefinite
SDG&E:
U.S. federal(1):
NOLs	$	279	Indefinite
General business tax credits	1		2044
U.S. state NOLs(1)	909		2043
SoCalGas:
U.S. federal NOLs(1)	$	2,857	Indefinite
U.S. state NOLs(1)	3,917		2042

(1)    We have recorded deferred income tax benefits on these NOLs and tax credits, in total, because we currently believe they will be realized on a more-likely-than-not-basis.

(2)    We have not recorded deferred income tax benefits on a portion of these NOLs and tax credits because we currently believe they will not be realized on a more-likely-than-not-basis, as we discuss below.

A valuation allowance is recorded when, based on more-likely-than-not criteria, negative evidence outweighs positive evidence with regard to our ability to realize a deferred income tax asset in the future. In the year ended December 31, 2024, we recognized income tax expense of $330 million from changes to a valuation allowance against foreign tax credits that were carried forward from the implementation of the Tax Cuts and Jobs Act of 2017. For various U.S. state and non-U.S. jurisdictions, the negative evidence outweighs the positive evidence primarily due to cumulative pretax losses resulting in deferred income tax assets that we currently do not believe will be realized on a more-likely-than-not basis.

The following table provides the valuation allowances that we recorded against a portion of our total deferred income tax assets shown above in the “Deferred Income Taxes – Sempra” table.

VALUATION ALLOWANCES BY JURISDICTION
(Dollars in millions)
	December 31,
	2024		2023
Sempra:
U.S. federal	$	406	$	108
U.S. state	47		51
Non-U.S.	50		30
	$	503	$	189

2024 Form 10-K | F-79

Following is a reconciliation of the changes in unrecognized income tax benefits and the potential effect on our ETR for the years ended December 31:

RECONCILIATION OF UNRECOGNIZED INCOME TAX BENEFITS
(Dollars in millions)
	2024		2023		2022
Sempra:
Balance at January 1	$	492	$	278	$	304
Increase in prior period tax positions	40		308		16
Decrease in prior period tax positions	(8)		(63)		(2)
Decrease in current period tax positions	—		(21)		—
Settlements with tax authorities	(15)		(16)		(43)
Expiration of statutes of limitations	—		—		(1)
Increase in current period tax positions	39		6		4
Balance at December 31	$	548	$	492	$	278
Of December 31 balance, amounts related to tax positions that if recognized in future years would
decrease the effective tax rate(1)	$	(229)	$	(224)	$	(117)
increase the effective tax rate(1)	1		1		38
SDG&E:
Balance at January 1	$	14	$	14	$	14
Increase in prior period tax positions	—		2		—
Settlements with tax authorities	—		(2)		—
Balance at December 31	$	14	$	14	$	14
Of December 31 balance, amounts related to tax positions that if recognized in future years would
decrease the effective tax rate(1)	$	(11)	$	(11)	$	(11)
increase the effective tax rate(1)	1		1		1
SoCalGas:
Balance at January 1	$	29	$	77	$	72
Increase in prior period tax positions	—		1		1
Decrease in prior period tax positions	—		(47)		—
Increase in current period tax positions	—		—		4
Settlements with tax authorities	—		(2)		—
Balance at December 31	$	29	$	29	$	77
Of December 31 balance, amounts related to tax positions that if recognized in future years would
decrease the effective tax rate(1)	$	(29)	$	(29)	$	(67)
increase the effective tax rate(1)	—		—		37

(1)    Includes temporary book and tax differences that are treated as flow-through for ratemaking purposes, as discussed above.

The California Franchise Tax Board is examining Sempra’s California unitary group for tax years 2018 and 2019. As of December 31, 2024, it is not reasonably possible this matter could be resolved within the next 12 months. We have included an increase in unrecognized income tax benefits in the reconciliation above.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting for gas repairs expenditures. SDG&E and SoCalGas elected this change in tax accounting method in Sempra’s consolidated 2023 income tax return filing and recorded additional income tax benefits of $34 million and $97 million, respectively, in 2023. Additionally, SoCalGas updated its assessment of prior years’ unrecognized income tax benefits and recorded an income tax benefit of $43 million in 2023 for previously unrecognized income tax benefits pertaining to gas repairs expenditures. Sempra elected this change in tax accounting method in its consolidated 2023 income tax return filing.

Sempra, SDG&E, and SoCalGas record regulatory liabilities for benefits that will be flowed through to customers in the future.

2024 Form 10-K | F-80

It is reasonably possible that within the next 12 months, unrecognized income tax benefits could decrease due to the following:

POSSIBLE DECREASES IN UNRECOGNIZED INCOME TAX BENEFITS WITHIN 12 MONTHS
(Dollars in millions)
	December 31,
	2024		2023		2022
Sempra:
Potential resolution of audit issues with various U.S. federal, state and local and non-U.S. taxing authorities	$	15	$	242	$	8
SDG&E:
Potential resolution of audit issues with various U.S. federal, state and local taxing authorities	$	6	$	6	$	6
SoCalGas:
Potential resolution of audit issues with various U.S. federal, state and local taxing authorities	$	2	$	2	$	2

Amounts accrued for interest and penalties associated with unrecognized income tax benefits are included in Income Tax Expense (Benefit) on the Consolidated Statements of Operations. Sempra accrued $15 million at both December 31, 2024 and 2023 on the Consolidated Balance Sheets, and negligible amounts in 2024, $2 million in 2023 and negligible amounts in 2022 on the Consolidated Statements of Operations for interest and penalties. SDG&E and SoCalGas each accrued negligible amounts for interest expense and penalties at December 31, 2024 and 2023 on the Consolidated Balance Sheets, and recorded negligible amounts for interest expense and penalties on the Consolidated Statements of Operations for all periods presented.

INCOME TAX AUDITS

Sempra is subject to U.S. federal income tax as well as income tax of multiple state and non-U.S. jurisdictions. We remain subject to examination for U.S. federal tax years after 2020. We are subject to examination by major state tax jurisdictions for tax years after 2012. Certain major non-U.S. income tax returns for tax years 2013 through the present are open to examination.

SDG&E and SoCalGas are subject to U.S. federal income tax and state income tax. They remain subject to examination for U.S. federal tax years after 2020 and state tax years after 2012.

In addition, Sempra has filed protests to contest proposed state audit adjustments for tax years 2009 through 2012. The pre-2013 tax years for our major state tax jurisdictions are closed to new issues; therefore, no additional tax may be assessed by the taxing authorities for these tax years.

SI Partners has filed an administrative appeal to contest a tax assessment issued by the Servicio de Administración Tributaria for tax year 2016. In 2023, we increased unrecognized income tax benefits in the table above, and will have the opportunity to contest any unresolved issues through the Mexican courts.

NOTE 8. EMPLOYEE BENEFIT PLANS

For our employee benefit plans, we:

▪recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status in the balance sheet;

▪measure a plan’s assets and its obligations that determine its funded status as of the end of the fiscal year; and

▪recognize changes in the funded status of pension and PBOP plans in the year in which the changes occur. Generally, those changes are reported in OCI and as a separate component of shareholders’ equity.

The detailed information presented below covers the employee benefit plans of primarily Sempra and its consolidated entities.

Sempra has funded and unfunded noncontributory traditional defined benefit and cash balance plans, including separate plans for SDG&E and SoCalGas, which collectively cover all eligible employees. Pension benefits under the traditional defined benefit plans are based on service and final average earnings, while the cash balance plans provide benefits using a career average earnings methodology.

IEnova has an unfunded noncontributory defined benefit plan covering all employees that provides defined benefits to retirees based on date of hire, years of service and final average earnings.

2024 Form 10-K | F-81

Sempra also has PBOP plans, including separate plans for SDG&E and SoCalGas, which collectively cover all domestic and certain foreign employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory. Participants’ contributions are adjusted annually. PBOP plans include medical benefits.

Pension and PBOP costs and obligations are dependent on assumptions used in calculating such amounts. We review these assumptions on an annual basis and update them as appropriate. We consider current market conditions, including interest rates, in making these assumptions.

DEDICATED ASSETS IN SUPPORT OF CERTAIN BENEFITS PLANS

In support of its Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans, Sempra maintains dedicated assets, including a Rabbi Trust and investments in life insurance contracts, which totaled $585 million and $549 million at December 31, 2024 and 2023, respectively.

PENSION AND PBOP PLANS

Oncor

In 2024 and 2023, we had $34 million and $38 million, respectively, in AOCI representing an actuarial loss related to Oncor’s pension plans.

Benefit Obligations and Assets

The following three tables provide a reconciliation of the changes in the plans’ projected benefit obligations and the fair value of assets during 2024 and 2023, and a statement of the funded status at December 31, 2024 and 2023.

PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
(Dollars in millions)
	Pension(1)				PBOP
	2024		2023		2024		2023
Sempra:
CHANGE IN PROJECTED BENEFIT OBLIGATION
Obligation at January 1	$	3,107	$	2,806	$	693	$	663
Service cost	132		109		15		13
Interest cost	166		157		36		37
Contributions from plan participants	—		—		23		23
Actuarial (gain) loss	(100)		190		(11)		28
Plan amendments	2		4		—		—
Benefit payments	(81)		(83)		(69)		(71)
Settlements	(87)		(76)		—		—
Obligation at December 31	3,139		3,107		687		693
CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1	2,664		2,390		1,169		1,096
Actual return on plan assets	196		218		57		117
Employer contributions	243		215		5		4
Contributions from plan participants	—		—		23		23
Benefit payments	(81)		(83)		(69)		(71)
Settlements	(87)		(76)		—		—
Fair value of plan assets at December 31	2,935		2,664		1,185		1,169
Funded status at December 31	$	(204)	$	(443)	$	498	$	476
Net recorded (liability) asset at December 31	$	(204)	$	(443)	$	498	$	476

(1)    The accumulated benefit obligation was $2,900 and $2,865 at December 31, 2024 and 2023, respectively.

2024 Form 10-K | F-82

PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
(Dollars in millions)
	Pension(1)				PBOP
	2024		2023		2024		2023
SDG&E:
CHANGE IN PROJECTED BENEFIT OBLIGATION
Obligation at January 1	$	807	$	714	$	140	$	134
Service cost	39		32		3		3
Interest cost	43		40		7		8
Contributions from plan participants	—		—		8		8
Actuarial (gain) loss	(28)		69		(6)		7
Benefit payments	(16)		(17)		(18)		(20)
Settlements	(23)		(31)		—		—
Obligation at December 31	822		807		134		140
CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1	726		670		150		147
Actual return on plan assets	63		52		5		14
Employer contributions	37		52		—		1
Contributions from plan participants	—		—		8		8
Benefit payments	(16)		(17)		(18)		(20)
Settlements	(23)		(31)		—		—
Fair value of plan assets at December 31	787		726		145		150
Funded status at December 31	$	(35)	$	(81)	$	11	$	10
Net recorded (liability) asset at December 31	$	(35)	$	(81)	$	11	$	10

(1)    The accumulated benefit obligation was $781 and $769 at December 31, 2024 and 2023, respectively.

PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
(Dollars in millions)
	Pension(1)				PBOP
(Dollars in millions)	2024		2023		2024		2023
SoCalGas:
CHANGE IN PROJECTED BENEFIT OBLIGATION
Obligation at January 1	$	1,977	$	1,814	$	521	$	497
Service cost	79		65		11		9
Interest cost	105		101		27		28
Contributions from plan participants	—		—		14		14
Actuarial (gain) loss	(70)		90		(4)		21
Plan amendments	2		—		—		—
Benefit payments	(56)		(58)		(47)		(48)
Settlements	(38)		(35)		—		—
Obligation at December 31	1,999		1,977		522		521
CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1	1,744		1,535		990		923
Actual return on plan assets	115		151		50		100
Employer contributions	172		151		1		1
Contributions from plan participants	—		—		14		14
Benefit payments	(56)		(58)		(47)		(48)
Settlements	(38)		(35)		—		—
Fair value of plan assets at December 31	1,937		1,744		1,008		990
Funded status at December 31	$	(62)	$	(233)	$	486	$	469
Net recorded (liability) asset at December 31	$	(62)	$	(233)	$	486	$	469

(1)    The accumulated benefit obligation was $1,824 and $1,799 at December 31, 2024 and 2023, respectively.

Actuarial (gains) losses fluctuate based on changes in assumptions that we describe below in “Assumptions for Pension and PBOP Plans” and updates to census data.

2024 Form 10-K | F-83

Pension Plans

▪In 2024, actuarial gains were driven by an increase in discount rates at SoCalGas and SDG&E, offset by updated census data at SoCalGas and SDG&E.

▪In 2023, actuarial losses were driven by a decrease in discount rates at SoCalGas and SDG&E, an increase in the interest crediting rate for cash balance plans at SDG&E and SoCalGas and updated census data at Sempra and SDG&E. These actuarial losses were partially offset by actuarial gains at SoCalGas due to a change in the rates to convert traditional pension benefits to lump-sums.

PBOP Plans

▪In 2024, actuarial gains were driven by an increase in discount rates at SoCalGas, partially offset by an increase in the 2025 expected healthcare costs at SoCalGas.

▪In 2023, actuarial losses were driven by a decrease in discount rates at SoCalGas and SDG&E.

Net Assets and Liabilities

The assets and liabilities of the pension and PBOP plans are affected by changing market conditions as well as when actual plan experience is different than assumed. Such events result in investment gains and losses, which we defer and recognize in pension and PBOP costs over a period of years. Our funded pension and PBOP plans use the asset smoothing method, except for those at SDG&E. This method develops an asset value that recognizes realized and unrealized investment gains and losses over a three-year period. This adjusted asset value, known as the market-related value of assets, is used in conjunction with an expected long-term rate of return to determine the expected return-on-plan-assets component of net periodic benefit cost. SDG&E does not use the asset smoothing method but rather recognizes realized and unrealized investment gains and losses during the current year.

The 10% corridor accounting method is used at Sempra, SDG&E and SoCalGas. Under the corridor accounting method, if as of the beginning of a year unrecognized net gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets, the excess is amortized over the average remaining service period of active participants (or, for plans where participants are substantially inactive employees, the average remaining lifetime of all participants or the period for which benefits will be paid, whichever is shorter). The asset smoothing and 10% corridor accounting methods help mitigate volatility of net periodic benefit costs from year to year.

Defined benefit pension and PBOP plans with an aggregated overfunded status are recognized as an asset and with an aggregated underfunded status are recognized as a liability; unrecognized changes in these assets and/or liabilities are normally recorded in AOCI on the balance sheet. SDG&E and SoCalGas record regulatory assets and liabilities that offset the funded pension and PBOP plans’ assets or liabilities, as these costs are expected to be recovered in future utility rates based on decisions by regulatory agencies.

SDG&E and SoCalGas record annual pension and PBOP net periodic benefit costs equal to the contributions to their qualified plans as authorized by the CPUC. The annual contributions to the pension plans are the greater of:

▪a minimum required funding amount as required by the IRS;

▪the amount required to maintain an 85% Adjusted Funding Target Attainment Percentage as defined by the Pension Protection Act of 2006, as amended; or

▪beginning January 1, 2024 and for the duration of the 2024 GRC cycle, a fixed amount equal to the estimated annual service cost as defined by U.S. GAAP plus one year of a seven-year amortization of the unfunded projected benefit obligation of the pension plan as of January 1, 2024, and limited to an annual amount that keeps the fair value of the pension plan assets from exceeding 110% of the pension benefit obligation of the plan.

The annual contributions to PBOP plans are equal to the lesser of the maximum tax-deductible amount or the net periodic benefit cost calculated in accordance with U.S. GAAP for pension and PBOP plans but not less than benefits paid directly by the employer (such as benefits paid to key employees). Any differences between booked net periodic benefit cost and amounts contributed to the pension and PBOP plans for SDG&E and SoCalGas are disclosed as regulatory adjustments in accordance with U.S. GAAP for rate-regulated entities.

2024 Form 10-K | F-84

The net (liability) asset is included in the following categories on the Consolidated Balance Sheets.

PENSION AND PBOP OBLIGATIONS, NET OF PLAN ASSETS
(Dollars in millions)
	Pension				PBOP
	December 31,
	2024		2023		2024		2023
Sempra:
Noncurrent assets	$	6	$	—	$	507	$	485
Current liabilities	(50)		(44)		(1)		(1)
Noncurrent liabilities	(160)		(399)		(8)		(8)
Net recorded (liability) asset	$	(204)	$	(443)	$	498	$	476
SDG&E:
Noncurrent assets	$	—	$	—	$	11	$	10
Current liabilities	(7)		(2)		—		—
Noncurrent liabilities	(28)		(79)		—		—
Net recorded (liability) asset	$	(35)	$	(81)	$	11	$	10
SoCalGas:
Noncurrent assets	$	—	$	—	$	486	$	469
Current liabilities	(17)		(2)		—		—
Noncurrent liabilities	(45)		(231)		—		—
Net recorded (liability) asset	$	(62)	$	(233)	$	486	$	469

Amounts recorded in AOCI, net of income tax effects and amounts recorded as regulatory assets, are as follows.

AMOUNTS IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Pension				PBOP
	December 31,
	2024		2023		2024		2023
Sempra:
Net actuarial (loss) gain	$	(120)	$	(124)	$	14	$	13
Prior service cost	(9)		(6)		—		—
Total	$	(129)	$	(130)	$	14	$	13
SDG&E:
Net actuarial loss	$	(12)	$	(8)
Total	$	(12)	$	(8)
SoCalGas:
Net actuarial loss	$	(14)	$	(10)
Prior service cost	(3)		(2)
Total	$	(17)	$	(12)

2024 Form 10-K | F-85

Sempra, SDG&E and SoCalGas each have a funded pension plan. The following table shows the obligations of funded pension plans with benefit obligations in excess of plan assets.

OBLIGATIONS OF FUNDED PENSION PLANS
(Dollars in millions)
	December 31,
	2024		2023
Sempra:
Projected benefit obligation	$	2,752	$	2,925
Accumulated benefit obligation	2,542		2,712
Fair value of plan assets	2,724		2,664
SDG&E:
Projected benefit obligation	$	793	$	781
Accumulated benefit obligation	755		746
Fair value of plan assets	787		726
SoCalGas:
Projected benefit obligation	$	1,959	$	1,944
Accumulated benefit obligation	1,787		1,771
Fair value of plan assets	1,937		1,744

We also have unfunded pension plans at Sempra, SDG&E, SoCalGas and IEnova. The following table shows the obligations of unfunded pension plans.

OBLIGATIONS OF UNFUNDED PENSION PLANS
(Dollars in millions)
	December 31,
	2024		2023
Sempra:
Projected benefit obligation	$	183	$	182
Accumulated benefit obligation	159		153
SDG&E:
Projected benefit obligation	$	29	$	26
Accumulated benefit obligation	26		23
SoCalGas:
Projected benefit obligation	$	40	$	33
Accumulated benefit obligation	37		28

Sempra, SDG&E and SoCalGas each have a funded PBOP plan. At December 31, 2024, Sempra’s, SDG&E’s and SoCalGas’ plan assets were each in excess of their respective obligations for funded PBOP plans with accumulated postretirement benefit obligations.

We also have unfunded PBOP plans at Sempra. The following table shows the obligations of unfunded PBOP plans.

OBLIGATIONS OF UNFUNDED PBOP PLANS
(Dollars in millions)
	December 31,
	2024		2023
Sempra:
Accumulated postretirement benefit obligation	$	9	$	9

2024 Form 10-K | F-86

Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost (which, other than the service cost component, are included in Other Income, Net) and pretax amounts recognized in OCI.

NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
(Dollars in millions)
	Pension						PBOP
	Years ended December 31,
	2024		2023		2022		2024		2023		2022
Sempra:
NET PERIODIC BENEFIT COST
Service cost	$	132	$	109	$	146	$	15	$	13	$	23
Interest cost	166		157		118		36		37		28
Expected return on plan assets	(178)		(169)		(183)		(70)		(69)		(64)
Amortization of:
Prior service cost (credit)	5		5		10		(2)		(2)		(2)
Actuarial loss (gain)	14		10		25		(17)		(23)		(15)
Settlement charges	9		—		28		—		—		—
Net periodic benefit cost (credit)	148		112		144		(38)		(44)		(30)
Regulatory adjustment	100		117		84		38		43		30
Total expense (income) recognized	248		229		228		—		(1)		—
CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI
Net (gain) loss	(2)		42		12		(1)		(2)		(4)
Prior service cost	3		4		—		—		—		—
Amortization of actuarial (loss) gain	(7)		(5)		(8)		1		2		1
Amortization of prior service cost	(3)		(2)		(4)		—		—		—
Settlements	(9)		—		—		—		—		—
Total recognized in OCI	(18)		39		—		—		—		(3)
Total recognized in net periodic benefit cost and OCI	$	230	$	268	$	228	$	—	$	(1)	$	(3)

NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
(Dollars in millions)
	Pension						PBOP
	Years ended December 31,
	2024		2023		2022		2024		2023		2022
SDG&E:
NET PERIODIC BENEFIT COST
Service cost	$	39	$	32	$	37	$	3	$	3	$	5
Interest cost	43		40		26		7		8		6
Expected return on plan assets	(45)		(39)		(46)		(9)		(8)		(10)
Amortization of:
Prior service cost	1		1		1		—		—		—
Actuarial loss (gain)	8		4		1		(1)		(2)		(2)
Settlement charges	—		—		14		—		—		—
Net periodic benefit cost (credit)	46		38		33		—		1		(1)
Regulatory adjustment	(8)		15		20		—		—		1
Total expense recognized	38		53		53		$	—	$	1	$	—
CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI
Net loss (gain)	4		3		(3)
Amortization of actuarial loss	(1)		—		(1)
Amortization of prior service cost	—		(1)		—
Total recognized in OCI	3		2		(4)
Total recognized in net periodic benefit cost and OCI	$	41	$	55	$	49

2024 Form 10-K | F-87

NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
(Dollars in millions)
	Pension						PBOP
	Years ended December 31,
	2024		2023		2022		2024		2023		2022
SoCalGas:
NET PERIODIC BENEFIT COST
Service cost	$	79	$	65	$	96	$	11	$	9	$	17
Interest cost	105		101		81		27		28		21
Expected return on plan assets	(121)		(119)		(126)		(59)		(59)		(53)
Amortization of:
Prior service cost (credit)	4		4		8		(3)		(2)		(2)
Actuarial loss (gain)	1		1		18		(14)		(19)		(12)
Settlement charges	—		—		14		—		—		—
Net periodic benefit cost (credit)	68		52		91		(38)		(43)		(29)
Regulatory adjustment	108		102		64		38		43		29
Total expense recognized	176		154		155		$	—	$	—	$	—
CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI
Net loss (gain)	4		2		(5)
Prior service cost	2		—		—
Amortization of actuarial loss	(1)		(1)		(2)
Amortization of prior service cost	(1)		(1)		(1)
Total recognized in OCI	4		—		(8)
Total recognized in net periodic benefit cost and OCI	$	180	$	154	$	147

Assumptions for Pension and PBOP Plans

Benefit Obligation and Net Periodic Benefit Cost

Except for the IEnova plans, we develop the discount rate assumptions using a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high-quality corporate bonds that generate sufficient cash flows to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of corporate bonds with a Bloomberg Composite of AA or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plans’ projected benefit payments discounted at this rate with the market value of the bonds selected.

We develop the discount rate assumptions for the plans at IEnova by constructing a synthetic government zero coupon bond yield curve from the available market data, based on duration matching, and we add a risk spread to allow for the yields of high-quality corporate bonds. Such method is required when there is no deep market for high quality corporate bonds.

Expected return on plan assets is based on the weighted average of the plans’ target investment allocation as of the measurement date and the expected returns for those asset types.

Interest crediting rate is based on an average 30-year Treasury bond from the month of November of the preceding year.

We amortize prior service cost using straight line amortization over average future service (or average expected lifetime for plans where participants are substantially inactive employees), which is an alternative method allowed under U.S. GAAP.

2024 Form 10-K | F-88

The significant assumptions affecting projected benefit obligation and net periodic benefit cost are as follows:

WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE PROJECTED BENEFIT OBLIGATION
	Pension				PBOP
	December 31,
	2024		2023		2024		2023
Sempra:
Discount rate	5.74	%	5.31	%	5.75	%	5.34	%
Interest crediting rate(1)(2)	4.54		4.66		4.54		4.66
Rate of compensation increase	2.70-10.00		2.70-10.00		2.70-10.00		2.70-10.00
SDG&E:
Discount rate	5.75	%	5.30	%	5.75	%	5.30	%
Interest crediting rate(1)(2)	4.54		4.66		4.54		4.66
Rate of compensation increase	3.50-10.00		3.50-10.00		3.50-10.00		3.50-10.00
SoCalGas:
Discount rate	5.70	%	5.25	%	5.75	%	5.35	%
Interest crediting rate(1)(2)	4.54		4.66		4.54		4.66
Rate of compensation increase	2.70-10.00		2.70-10.00		2.70-10.00		2.70-10.00

(1)    Interest crediting rate for pension benefits applies only to funded cash balance plans.

(2)    Interest crediting rate for PBOP applies only to interest bearing health retirement accounts at SDG&E and SoCalGas.

WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE NET PERIODIC BENEFIT COST
	Pension						PBOP
	Years ended December 31,
	2024		2023		2022		2024		2023		2022
Sempra:
Discount rate	5.31	%	5.63	%	3.04	%	5.34	%	5.65	%	3.04	%
Expected return on plan assets	6.56		6.48		6.27		5.90		5.51		4.77
Interest crediting rate(1)(2)	4.66		3.99		1.94		4.66		3.99		1.94
Rate of compensation increase	2.70-10.00		2.70-10.00		2.70-10.00		2.70-10.00		2.70-10.00		2.70-10.00
SDG&E:
Discount rate	5.30	%	5.60	%	2.99	%	5.30	%	5.65	%	3.05	%
Expected return on plan assets	6.25		6.00		5.50		5.88		5.52		4.80
Interest crediting rate(1)(2)	4.66		3.99		1.94		4.66		3.99		1.94
Rate of compensation increase	3.50-10.00		3.50-10.00		3.50-10.00		3.50-10.00		3.50-10.00		3.50-10.00
SoCalGas:
Discount rate	5.25	%	5.60	%	3.04	%	5.35	%	5.65	%	3.05	%
Expected return on plan assets	6.75		6.75		6.75		5.86		5.47		4.71
Interest crediting rate(1)(2)	4.66		3.99		1.94		4.66		3.99		1.94
Rate of compensation increase	2.70-10.00		2.70-10.00		2.70-10.00		2.70-10.00		2.70-10.00		2.70-10.00

(1)    Interest crediting rate for pension benefits applies only to funded cash balance plans.

(2)    Interest crediting rate for PBOP applies only to interest bearing health retirement accounts at SDG&E and SoCalGas.

2024 Form 10-K | F-89

Health Care Cost Trend Rates

Assumed health care cost trend rates have a significant effect on the amounts that Sempra, SDG&E and SoCalGas report for the health care plan costs. Following are the health care cost trend rates applicable to our PBOP plans:

ASSUMED HEALTH CARE COST TREND RATES
	PBOP
	Pre-65 retirees						Retirees aged 65 years and older
	Years ended December 31,
	2024		2023		2022		2024		2023		2022
Health care cost trend rate assumed for next year	6.50	%	6.00	%	6.00	%	4.50	%	4.50	%	4.50	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend)	4.75	%	4.75	%	4.75	%	4.50	%	4.50	%	4.50	%
Year the rate reaches the ultimate trend	2030		2028		2028		2022		2022		2022

Plan Assets

Investment Strategy for Sempra’s Pension Master Trust

Sempra’s pension master trust holds the investments for our pension plans and a portion of the investments for our PBOP plans. We maintain additional trusts, as we discuss below, for certain of SDG&E’s and SoCalGas’ PBOP plans. Other than through indexing and certain collective investment strategies, the trusts do not invest in securities of Sempra.

The current asset allocation objective for the pension master trust is to protect the funded status of the plans while generating sufficient returns to cover future benefit payments and accruals. A portion of the pension master trust is invested in accordance with plan specific de-risking glidepaths designed to reduce the assets’ exposure to risk as the plans become better funded. We assess the portfolio performance by comparing actual returns with relevant benchmarks. The target asset allocations for Sempra’s pension plans are between return-seeking assets (i.e., generally, equity securities, diversified real assets, high-yield fixed income securities and other instruments with a similar risk profile) and risk-mitigating assets (i.e., generally, government and corporate fixed income securities) as follows:

TARGET ASSET ALLOCATIONS FOR PENSION PLANS
(Dollars in millions)
	Sempra		SDG&E		SoCalGas
Return-seeking assets	34	%	42	%	49	%
Risk-mitigating assets	66	%	58	%	51	%

We maintain asset allocations at strategic levels within reasonable bands of variance. The asset allocations are reviewed by our Plan Funding Committee and our Pension and Benefits Investment Committee (the Committees) on a regular basis to help ensure that plan assets are positioned to meet plan obligations. When evaluating strategic asset allocations, the Committees consider many variables, including:

▪long-term cost

▪variability and level of contributions

▪funded status

▪a range of expected outcomes over varying confidence levels

In accordance with the Sempra pension investment guidelines, derivative financial instruments may be used by the pension master trust’s equity and fixed income portfolio investment managers to equitize cash, hedge certain exposures, and as substitutes for certain types of fixed income securities.

Rate of Return Assumption

The expected return on plan assets in our pension and PBOP plans is based on the weighted average of the plans’ target investment allocations to specific asset classes as of the measurement date. We expect a return of between 4% and 12% on return-seeking assets and between 2% and 6% for risk-mitigating assets. Certain trusts that hold assets for SDG&E’s and SoCalGas’ PBOP plans are subject to taxation, which impacts the expected after-tax return on plan assets.

2024 Form 10-K | F-90

Concentration of Risk

Plan assets are diversified across global equity and bond markets, and concentration of risk in any one economic, industry, maturity or geographic sector is limited.

Investment Strategy for Sempra’s, SDG&E’s and SoCalGas’ PBOP Plans

Sempra’s PBOP plan is funded by cash contributions from Sempra. SDG&E’s and SoCalGas’ PBOP plans are funded by cash contributions from SDG&E and SoCalGas and their current retirees. The assets of these plans are placed into the pension master trust and other Voluntary Employee Beneficiary Association trusts. Specific target asset allocations are periodically reviewed to help ensure that plan assets are positioned to meet plan obligations. The target asset allocations for the PBOP plans are between return-seeking assets and risk-mitigating assets as follows:

TARGET ASSET ALLOCATIONS FOR PBOP PLANS
(Dollars in millions)
	Sempra		SDG&E and SoCalGas
	Assets held in pension master trust		Assets held in pension master trust		Assets held in Voluntary Employee Beneficiary Association trusts
Return-seeking assets	74	%	38	%	30	%
Risk-mitigating assets	26	%	62	%	70	%

Fair Value of Pension and PBOP Plan Assets

We classify the investments in Sempra’s pension master trust and the trusts for SDG&E’s and SoCalGas’ PBOP plans based on the fair value hierarchy, except for certain investments measured using NAV as a practical expedient for fair value.

The following are descriptions of the valuation methods and assumptions we use to estimate the fair values of investments held by pension and PBOP plan trusts.

Equity Securities – Equity securities are valued using quoted prices listed on nationally recognized securities exchanges.

Registered Investment Companies – Investments in mutual funds sponsored by a registered investment company are valued based on exchange listed prices. Where the value is a quoted price in an active market, the investment is classified within Level 1 of the fair value hierarchy. Other investments are valued under a discounted cash flow approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks.

Fixed Income Securities – Certain fixed income securities are valued at the closing price reported in the active market in which the security is traded. Other fixed income securities are valued based on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar securities, the security is valued under a discounted cash flow approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks. Certain high yield fixed-income securities are valued by applying a price adjustment to the bid side to calculate a mean and ask value. Adjustments can vary based on maturity, credit standing, and reported trade frequencies. The bid to ask spread is determined by the investment manager based on the review of the available market information.

Common/Collective Trusts – Investments in common/collective trust funds are valued based on the NAV of units owned, which is based on the current fair value of the funds’ underlying assets.

Derivative Financial Instruments – Futures contracts that are publicly traded in active markets are valued at closing prices as of the last business day of the year. Forward currency contracts are valued at the prevailing forward exchange rate of the underlying currencies, and unrealized gain (loss) is recorded daily. Fixed income futures and options are marked to market daily. Equity index futures contracts are valued at the last sales price quoted on the exchange on which they primarily trade.

While management believes the valuation methods described above are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

We provide more discussion of fair value measurements in Notes 1 and 10. The following tables set forth by level within the fair value hierarchy a summary of the investments in our pension and PBOP plan trusts measured at fair value on a recurring basis.

2024 Form 10-K | F-91

The fair values by asset category are as follows:

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PENSION PLANS
(Dollars in millions)
	Fair value at December 31, 2024
	Level 1		Level 2		Total
SDG&E:
Cash and cash equivalents	$	2	$	—	$	2
Equity securities:
Domestic	9		—		9
International	5		—		5
Registered investment companies – Domestic	48		—		48
Fixed income securities:
Domestic government and government agencies	227		5		232
International government bonds	—		3		3
Domestic corporate bonds	—		65		65
International corporate bonds	—		8		8
Derivative financial instruments	6		—		6
Total investment assets in the fair value hierarchy	297		81		378
Accounts receivable/payable, net					3
Investments measured at NAV – Common/collective trusts					406
Total SDG&E investment assets					787
SoCalGas:
Cash and cash equivalents	8		—		8
Equity securities:
Domestic	27		—		27
International	14		—		14
Registered investment companies – Domestic	149		—		149
Fixed income securities:
Domestic government and government agencies	270		17		287
International government bonds	—		9		9
Domestic corporate bonds	—		201		201
International corporate bonds	—		26		26
Derivative financial instruments	(4)		1		(3)
Total investment assets in the fair value hierarchy	464		254		718
Accounts receivable/payable, net					22
Investments measured at NAV – Common/collective trusts					1,197
Total SoCalGas investment assets					1,937

2024 Form 10-K | F-92

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PENSION PLANS (CONTINUED)
(Dollars in millions)
	Fair value at December 31, 2024
	Level 1		Level 2		Total
Other Sempra:
Equity securities:
Domestic	$	2	$	—	$	2
International	1		—		1
Registered investment companies – Domestic	10		—		10
Fixed income securities:
Domestic government and government agencies	77		3		80
International government bonds	—		1		1
Domestic corporate bonds	—		14		14
International corporate bonds	—		2		2
Derivative financial instruments	1		—		1
Total investment assets in the fair value hierarchy	91		20		111
Accounts receivable/payable, net					1
Investments measured at NAV – Common/collective trusts					99
Total Other Sempra investment assets					211
Total Sempra investment assets in the fair value hierarchy	$	852	$	355
Total Sempra investment assets					$	2,935

2024 Form 10-K | F-93

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PENSION PLANS
(Dollars in millions)
	Fair value at December 31, 2023
	Level 1		Level 2		Total
SDG&E:
Cash and cash equivalents	$	17	$	—	$	17
Equity securities:
Domestic	103		—		103
International	40		—		40
Registered investment companies – Domestic	41		—		41
Fixed income securities:
Domestic government and government agencies	240		5		245
International government bonds	—		2		2
Domestic corporate bonds	—		62		62
International corporate bonds	—		8		8
Derivative financial instruments	(15)		—		(15)
Total investment assets in the fair value hierarchy	426		77		503
Accounts receivable/payable, net					1
Investments measured at NAV:
Common/collective trusts					214
Other					8
Total SDG&E investment assets					726
SoCalGas:
Cash and cash equivalents	3		—		3
Equity securities:
Domestic	353		1		354
International	137		—		137
Registered investment companies – Domestic	141		1		142
Fixed income securities:
Domestic government and government agencies	310		16		326
International government bonds	—		5		5
Domestic corporate bonds	—		212		212
International corporate bonds	—		27		27
Derivative financial instruments	11		—		11
Total investment assets in the fair value hierarchy	955		262		1,217
Accounts receivable/payable, net					(12)
Investments measured at NAV:
Common/collective trusts					513
Other					26
Total SoCalGas investment assets					1,744

2024 Form 10-K | F-94

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PENSION PLANS (CONTINUED)
(Dollars in millions)
	Fair value at December 31, 2023
	Level 1		Level 2		Total
Other Sempra:
Cash and cash equivalents	$	7	$	—	$	7
Equity securities:
Domestic	22		1		23
International	8		—		8
Registered investment companies – Domestic	8		—		8
Fixed income securities:
Domestic government and government agencies	78		2		80
Domestic corporate bonds	—		13		13
International corporate bonds	—		2		2
Derivative financial instruments	(5)		—		(5)
Total investment assets in the fair value hierarchy	118		18		136
Investments measured at NAV:
Common/collective trusts					56
Other					2
Total Other Sempra investment assets					194
Total Sempra investment assets in the fair value hierarchy	$	1,499	$	357
Total Sempra investment assets					$	2,664

The fair values by asset category of the PBOP plan assets held in the pension master trust and in the additional trusts for SoCalGas’ PBOP plans and SDG&E’s PBOP plan trusts are as follows:

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PBOP PLANS
(Dollars in millions)
	Fair value at December 31, 2024
	Level 1		Level 2		Total
SDG&E:
Cash and cash equivalents	$	1	$	—	$	1
Equity securities – Domestic	1		—		1
Registered investment companies:
Domestic	74		—		74
International	8		—		8
Fixed income securities:
Domestic government and government agencies	8		—		8
Domestic corporate bonds	—		5		5
International corporate bonds	—		1		1
Derivative financial instruments	(1)		—		(1)
Total investment assets in the fair value hierarchy	91		6		97
Accounts receivable/payable, net					1
Investments measured at NAV:
Common/collective trusts					21
Other					26
Total SDG&E investment assets					145

2024 Form 10-K | F-95

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PBOP PLANS (CONTINUED)
(Dollars in millions)
	Fair value at December 31, 2024
	Level 1		Level 2		Total
SoCalGas:
Cash and cash equivalents	$	2	$	—	$	2
Equity securities:
Domestic	5		—		5
International	2		—		2
Registered investment companies – Domestic	87		103		190
Fixed income securities:
Domestic government and government agencies	74		14		88
International government bonds	—		10		10
Domestic corporate bonds	—		295		295
International corporate bonds	—		45		45
Derivative financial instruments	1		—		1
Total investment assets in the fair value hierarchy	171		467		638
Accounts receivable/payable, net					9
Investments measured at NAV – Common/collective trusts					361
Total SoCalGas investment assets					1,008
Other Sempra:
Equity securities – International	1		—		1
Registered investment companies – Domestic	4		—		4
Fixed income securities:
Domestic government and government agencies	—		1		1
Domestic corporate bonds	—		4		4
Total investment assets in the fair value hierarchy	5		5		10
Investments measured at NAV – Common/collective trusts					22
Total Other Sempra investment assets					32
Total Sempra investment assets in the fair value hierarchy	$	267	$	478
Total Sempra investment assets					$	1,185

2024 Form 10-K | F-96

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PBOP PLANS
(Dollars in millions)
	Fair value at December 31, 2023
	Level 1		Level 2		Total
SDG&E:
Equity securities:
Domestic	$	8	$	—	$	8
International	3		—		3
Registered investment companies:
Domestic	71		—		71
International	7		—		7
Fixed income securities:
Domestic government and government agencies	12		1		13
Domestic corporate bonds	—		5		5
International corporate bonds	—		1		1
Derivative financial instruments	2		—		2
Total investment assets in the fair value hierarchy	103		7		110
Accounts receivable/payable, net					(2)
Investments measured at NAV:
Common/collective trusts					10
Other					32
Total SDG&E investment assets					150
SoCalGas:
Cash and cash equivalents	7		—		7
Equity securities:
Domestic	57		—		57
International	22		—		22
Registered investment companies – Domestic	78		103		181
Fixed income securities:
Domestic government and government agencies	128		14		142
International government bonds	—		9		9
Domestic corporate bonds	—		295		295
International corporate bonds	—		42		42
Derivative financial instruments	(6)		—		(6)
Total investment assets in the fair value hierarchy	286		463		749
Accounts receivable/payable, net					4
Investments measured at NAV:
Common/collective trusts					233
Other					4
Total SoCalGas investment assets					990

2024 Form 10-K | F-97

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PBOP PLANS (CONTINUED)
(Dollars in millions)
	Fair value at December 31, 2023
	Level 1		Level 2		Total
Other Sempra:
Equity securities:
Domestic	$	7	$	—	$	7
International	3		—		3
Registered investment companies – Domestic	3		—		3
Fixed income securities:
Domestic government and government agencies	2		1		3
Domestic corporate bonds	—		4		4
International corporate bonds	—		1		1
Total investment assets in the fair value hierarchy	15		6		21
Investments measured at NAV:
Common/collective trusts					7
Other					1
Total Other Sempra investment assets					29
Total Sempra investment assets in the fair value hierarchy	$	404	$	476
Total Sempra investment assets					$	1,169

Future Payments

We expect to contribute the following amounts to our pension and PBOP plans in 2025:

EXPECTED CONTRIBUTIONS
(Dollars in millions)
	Sempra		SDG&E		SoCalGas
Pension plans	$	280	$	54	$	188
PBOP plans	3		1		1

The following table shows the total benefits we expect to pay for the next 10 years to current employees and retirees from the plans or from company assets.

EXPECTED BENEFIT PAYMENTS
(Dollars in millions)
	Sempra				SDG&E				SoCalGas
	Pension		PBOP		Pension		PBOP		Pension		PBOP
2025	$	276	$	48	$	68	$	11	$	162	$	35
2026	246		50		63		10		151		34
2027	258		46		62		10		146		34
2028	236		46		67		10		144		34
2029	230		46		61		10		143		34
2030-2034	1,161		229		305		47		721		171

SAVINGS PLANS

Sempra, SDG&E and SoCalGas offer trusteed savings plans to all employees. Employee participation, employee contributions and employer matching contributions are subject to the provisions of the respective plans, and for employee contributions, limits imposed by the respective governmental authorities.

2024 Form 10-K | F-98

Employer contributions to the savings plans were as follows:

EMPLOYER CONTRIBUTIONS TO SAVINGS PLANS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra	$	65	$	59	$	64
SDG&E	22		20		19
SoCalGas	33		32		30

The market value of Sempra common stock held by the savings plans was $1.2 billion and $1.1 billion at December 31, 2024 and 2023, respectively.

NOTE 9. DERIVATIVE FINANCIAL INSTRUMENTS

We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposures are commodity market risk, benchmark interest rate risk and foreign exchange rate exposures. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that could cause our asset values to fall or our liabilities to increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not included in the tables below.

In certain cases, we apply the normal purchase or sale exception to contracts that otherwise would have been accounted for as derivative instruments and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below.

In all other cases, we record derivatives at fair value on the Consolidated Balance Sheets. We may have derivatives that are (1) cash flow hedges, (2) fair value hedges, or (3) undesignated. Depending on the applicability of hedge accounting and, for SDG&E and SoCalGas and other operations subject to regulatory accounting, the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in OCI (cash flow hedges), on the balance sheet (regulatory offsets), or recognized in earnings (fair value hedges and undesignated derivatives not subject to rate recovery). We classify cash flows from the (1) principal settlements of cross-currency swaps that hedge exposure related to Mexican peso-denominated debt and amounts related to terminations or early settlements of interest rate swaps as financing activities, (2) principal settlements of interest rate swaps associated with capitalized interest costs incurred to finance capital projects as investing activities, and (3) settlements of other derivative instruments as operating activities on the Consolidated Statements of Cash Flows.

HEDGE ACCOUNTING

We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated cash flows associated with revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments, foreign currency instruments and interest rate instruments. Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk of variability of future cash flows of a given revenue or expense item, and other criteria.

2024 Form 10-K | F-99

ENERGY DERIVATIVES

Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business, as follows:

▪SDG&E and SoCalGas use natural gas derivatives and SDG&E uses electricity derivatives, for the benefit of customers, with the objective of managing price risk and basis risk, and stabilizing and lowering natural gas and electricity costs. These derivatives include fixed-price natural gas and electricity positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments, or bilateral physical transactions. This activity is governed by risk management and transacting activity plans limited by company policy. SDG&E’s risk management and transacting activity plans for electricity derivatives are also required to be filed with, and have been approved by, the CPUC. SoCalGas is also subject to certain regulatory requirements and thresholds related to natural gas procurement under the GCIM. Natural gas and electricity derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Consolidated Statements of Operations are reflected in Cost of Natural Gas or in Cost of Electric Fuel and Purchased Power.

▪SDG&E is allocated and may purchase CRRs, which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations.

▪Sempra Infrastructure may use natural gas and electricity derivatives, as appropriate, in an effort to optimize the earnings of its assets which support the following businesses: LNG, natural gas pipelines and storage, and power generation. Gains and losses associated with undesignated derivatives are recognized in Energy-Related Businesses Revenues on the Consolidated Statements of Operations.

▪From time to time, our various businesses, including SDG&E and SoCalGas, may use other derivatives to hedge exposures such as GHG allowances.

The following table summarizes net energy derivative volumes.

NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
		December 31,
Commodity	Unit of measure	2024	2023
Sempra:
Natural gas	MMBtu	637	361
Electricity	MWh	—	1
Congestion revenue rights	MWh	27	36
SDG&E:
Natural gas	MMBtu	16	17
Congestion revenue rights	MWh	27	36
SoCalGas:
Natural gas	MMBtu	347	268

INTEREST RATE DERIVATIVES

We are exposed to interest rates primarily as a result of our current and expected use of financing. SDG&E and SoCalGas, as well as Sempra and its other subsidiaries and JVs, periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. In addition, we may utilize interest rate swaps, typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings.

2024 Form 10-K | F-100

In March 2023, Port Arthur LNG entered into floating-to-fixed interest rate swaps maturing in 2048, which were designated as cash flow hedges. On September 30, 2024, Port Arthur LNG voluntarily de-designated those interest rate swaps that begin hedging interest payments in March 2026 to provide for future financing flexibility. At the time of de-designation, $40 million of deferred gains related to the de-designated notional amount were included in AOCI, which will remain in AOCI until the hedged interest payments impact net income or such hedged interest payments become probable of not occurring. In October 2024, Port Arthur LNG received a cash settlement of $46 million, net of transaction costs, for the termination of $1.0 billion of the notional amount of both the designated and de-designated interest rate swaps, with the associated deferred gains remaining in AOCI. On December 31, 2024, Port Arthur LNG voluntarily de-designated the remaining interest rate swaps, which are currently hedging interest payments until March 2026. At the time of de-designation, $37 million of deferred gains related to the de-designated notional amount were included in AOCI, which will remain in AOCI until either the hedged interest payments impact net income or such hedged interest payments become probable of not occurring.

The following table presents the notional amounts of our interest rate derivatives, excluding those in our equity method investments.

INTEREST RATE DERIVATIVES
(Dollars in millions)
	December 31, 2024			December 31, 2023
	Notional amount		Maturities	Notional amount		Maturities
Sempra:
Cash flow hedges(1)	$	271	2025-2034	$	4,451	2024-2048
Undesignated derivatives	3,189		2025-2048	—		—

(1)    At December 31, 2024 and 2023, cash flow hedges accrued interest based on a notional amount of $271 and $488, respectively.

FOREIGN CURRENCY DERIVATIVES

We may utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries and JVs. These cash flow hedges exchange our Mexican peso-denominated principal and interest payments into the U.S. dollar and swap Mexican fixed interest rates for U.S. fixed interest rates. From time to time, Sempra Infrastructure and its JVs may use other foreign currency derivatives to hedge exposures related to cash flows associated with revenues from contracts denominated in Mexican pesos that are indexed to the U.S. dollar.

In May 2024, Oncor entered into cross-currency swaps designated as fair value hedges intended to offset foreign currency exchange rate risk related to its Euro-denominated debt.

We are also exposed to exchange rate movements at our Mexican subsidiaries and JVs, which have U.S. dollar-denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities denominated in the Mexican peso, which must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. We may utilize foreign currency derivatives as a means to manage the risk of exposure to significant fluctuations in our income tax expense and equity earnings from these impacts; however, we generally do not hedge our deferred income tax assets and liabilities or for inflation.

The following table presents the notional amounts of our foreign currency derivatives, excluding those in our equity method investments.

FOREIGN CURRENCY DERIVATIVES
(Dollars in millions)
	December 31, 2024			December 31, 2023
	Notional amount		Maturities	Notional amount		Maturities
Sempra:
Foreign currency derivatives	$	162	2025-2026	$	176	2024-2025

2024 Form 10-K | F-101

FINANCIAL STATEMENT PRESENTATION

The Consolidated Balance Sheets reflect the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Consolidated Balance Sheets, including the amount of cash collateral receivables that were not offset because the cash collateral was in excess of liability positions. We discuss the fair value of derivative assets and liabilities in Note 10.

DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31, 2024
	Current assets: Fixed-price contracts and other derivatives(1)		Other long-term assets		Other current liabilities		Deferred credits and other
Sempra:
Derivatives designated as hedging instruments:
Interest rate instruments	$	7	$	28	$	—	$	—
Foreign exchange instruments	4		1		—		—
Derivatives not designated as hedging instruments:
Interest rate instruments	12		246		—		—
Commodity contracts not subject to rate recovery	16		23		(21)		(43)
Associated offsetting commodity contracts	(15)		(23)		15		23
Commodity contracts subject to rate recovery	7		4		(55)		(10)
Associated offsetting commodity contracts	(5)		(2)		5		2
Associated offsetting cash collateral	—		—		10		4
Net amounts presented on the balance sheet	26		277		(46)		(24)
Additional cash collateral for commodity contracts not subject to rate recovery	40		—		—		—
Additional cash collateral for commodity contracts subject to rate recovery	25		—		—		—
Total(2)	$	91	$	277	$	(46)	$	(24)
SDG&E:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	4	$	4	$	(13)	$	(6)
Associated offsetting commodity contracts	(2)		(2)		2		2
Associated offsetting cash collateral	—		—		10		4
Net amounts presented on the balance sheet	2		2		(1)		—
Additional cash collateral for commodity contracts subject to rate recovery	21		—		—		—
Total(2)	$	23	$	2	$	(1)	$	—
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	3	$	—	$	(42)	$	(4)
Associated offsetting commodity contracts	(3)		—		3		—
Net amounts presented on the balance sheet	—		—		(39)		(4)
Additional cash collateral for commodity contracts subject to rate recovery	4		—		—		—
Total	$	4	$	—	$	(39)	$	(4)

(1)    Included in Other Current Assets for SDG&E and SoCalGas.

(2)    Normal purchase contracts previously measured at fair value are excluded.

2024 Form 10-K | F-102

DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	December 31, 2023
	Current assets: Fixed-price contracts and other derivatives(1)		Other long-term assets		Other current liabilities		Deferred credits and other
Sempra:
Derivatives designated as hedging instruments:
Interest rate instruments	$	17	$	70	$	—	$	—
Foreign exchange instruments	—		—		(9)		—
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery	173		52		(170)		(56)
Associated offsetting commodity contracts	(169)		(51)		169		51
Commodity contracts subject to rate recovery	10		8		(228)		(9)
Associated offsetting commodity contracts	(5)		(2)		5		2
Associated offsetting cash collateral	—		—		12		7
Net amounts presented on the balance sheet	26		77		(221)		(5)
Additional cash collateral for commodity contracts not subject to rate recovery	74		—		—		—
Additional cash collateral for commodity contracts subject to rate recovery	22		—		—		—
Total(2)	$	122	$	77	$	(221)	$	(5)
SDG&E:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	9	$	8	$	(18)	$	(9)
Associated offsetting commodity contracts	(5)		(2)		5		2
Associated offsetting cash collateral	—		—		12		7
Net amounts presented on the balance sheet	4		6		(1)		—
Additional cash collateral for commodity contracts subject to rate recovery	21		—		—		—
Total(2)	$	25	$	6	$	(1)	$	—
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	1	$	—	$	(210)	$	—
Net amounts presented on the balance sheet	1		—		(210)		—
Additional cash collateral for commodity contracts subject to rate recovery	1		—		—		—
Total	$	2	$	—	$	(210)	$	—

(1)    Included in Other Current Assets for SDG&E and SoCalGas.

(2)    Normal purchase contracts previously measured at fair value are excluded.

2024 Form 10-K | F-103

The following table includes the effects of derivative instruments designated as hedges on the Consolidated Statements of Operations and in OCI and AOCI.

HEDGE IMPACTS
(Dollars in millions)
	Pretax gain (loss)  recognized in OCI							Pretax gain (loss) reclassified from AOCI into earnings
	Years ended December 31,							Years ended December 31,
	2024		2023		2022		Location	2024		2023		2022
Sempra:
Cash flow hedges:
Interest rate instruments	$	36	$	45	$	40	Interest expense	$	11	$	(1)	$	(1)
Interest rate instruments	21		20		205		Equity earnings(1)	23		48		(29)
Foreign exchange instruments	14		(2)		(8)		Revenues: Energy- related businesses	5		(1)		1
							Other income, net	2		(2)		(1)
Foreign exchange instruments	12		(3)		(5)		Equity earnings(1)	6		(2)		—
Interest rate and foreign exchange instruments	—		7		25		Interest expense	—		1		2
							Other income, net	—		6		12
Fair value hedges:
Foreign exchange instruments	2		—		—		Equity earnings(1)	—		—		—
Total	$	85	$	67	$	257		$	47	$	49	$	(16)
SoCalGas:
Cash flow hedges:
Interest rate instruments	$	—	$	—	$	—	Interest expense	$	(1)	$	(1)	$	(1)

(1)    Equity earnings at Oncor Holdings and our foreign equity method investees are recognized after tax.

For Sempra, we expect that net gains before NCI of $29 million, which are net of income tax expense, that are currently recorded in AOCI (with net gains of $10 million attributable to NCI) related to cash flow hedges will be reclassified into earnings during the next 12 months as the hedged items affect earnings. SoCalGas expects that $1 million of losses, net of income tax benefit, that are currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next 12 months as the hedged items affect earnings. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts mature.

At December 31, 2024, the maximum length of time over which Sempra is hedging its exposure to the variability in future cash flows for forecasted transactions, excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is approximately one year.

2024 Form 10-K | F-104

The following table summarizes the effects of derivative instruments not designated as hedging instruments on the Consolidated Statements of Operations.

UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
		Pretax gain (loss) on derivatives recognized in earnings
		Years ended December 31,
	Location	2024		2023		2022
Sempra:
Commodity contracts not subject to rate recovery	Revenues: Energy-related businesses	$	223	$	919	$	(1,116)
Commodity contracts subject to rate recovery	Cost of natural gas	(56)		(288)		(56)
Commodity contracts subject to rate recovery	Cost of electric fuel and purchased power	(41)		15		202
Interest rate instruments	Interest expense	243		(47)		33
Total		$	369	$	599	$	(937)
SDG&E:
Commodity contracts subject to rate recovery	Cost of electric fuel and purchased power	$	(41)	$	15	$	202
SoCalGas:
Commodity contracts subject to rate recovery	Cost of natural gas	$	(56)	$	(288)	$	(56)

CREDIT RISK RELATED CONTINGENT FEATURES

For Sempra, SDG&E and SoCalGas, certain of our derivative instruments contain credit limits which vary depending on our credit ratings. Generally, these provisions, if applicable, may reduce our credit limit if a specified credit rating agency reduces our ratings. In certain cases, if our credit ratings were to fall below investment grade, the counterparty to these derivative liability instruments could request immediate payment or demand immediate and ongoing full collateralization.

For Sempra, the total fair value of this group of derivative instruments in a liability position at December 31, 2024 and 2023 was $122 million and $215 million, respectively. For SoCalGas, the total fair value of this group of derivative instruments in a liability position at December 31, 2024 and 2023 was $42 million and $210 million, respectively. SDG&E had a negligible amount of derivative instruments in a liability position at December 31, 2024 and no such instruments at December 31, 2023. At December 31, 2024, if the credit ratings of Sempra or SoCalGas were reduced below investment grade, $120 million and $42 million, respectively, of additional assets could be required to be posted as collateral for these derivative contracts.

For Sempra, SDG&E and SoCalGas, some of our derivative contracts contain a provision that would permit the counterparty, in certain circumstances, to request adequate assurance of our performance under the contracts. Such additional assurance, if needed, is not material and is not included in the amounts above.

2024 Form 10-K | F-105

NOTE 10. FAIR VALUE MEASUREMENTS

RECURRING FAIR VALUE MEASURES

The tables below set forth our financial assets and liabilities, by level within the fair value hierarchy, that were accounted for at fair value on a recurring basis at December 31, 2024 and 2023. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair-valued assets and liabilities and their placement within the fair value hierarchy.

The determination of fair values, shown in the tables below, incorporates various factors, including but not limited to, the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests).

Our financial assets and liabilities that were accounted for at fair value on a recurring basis in the tables below include the following:

▪Nuclear decommissioning trusts reflect the assets of SDG&E’s NDT, excluding accounts receivable and accounts payable. A third-party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2).

▪For commodity contracts, interest rate instruments and foreign exchange instruments, we primarily use a market or income approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). Level 3 recurring items relate to CRRs and, until December 31, 2022, fixed-price electricity positions, at SDG&E, as we discuss below in “Level 3 Information – SDG&E.” We further discuss derivative assets and liabilities in Note 9.

▪Rabbi Trust investments include short-term investments that consist of money market and mutual funds that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1).

▪As we discuss in Note 5, in July 2020, Sempra entered into a Support Agreement for the benefit of CFIN. We measure the Support Agreement, which includes a guarantee obligation, a put option and a call option, net of related guarantee fees, at fair value on a recurring basis. We use a discounted cash flow model to value the Support Agreement, net of related guarantee fees. Because some of the inputs that are significant to the valuation are less observable, the Support Agreement is classified as Level 3, as we describe below in “Level 3 Information – Other Sempra.”

2024 Form 10-K | F-106

RECURRING FAIR VALUE MEASURES
(Dollars in millions)
	Fair value at December 31, 2024
	Level 1		Level 2		Level 3		Netting(1)		Total
Sempra:
Assets:
Nuclear decommissioning trusts:
Short-term investments, primarily cash equivalents	$	8	$	2	$	—			$	10
Equity securities	295		3		—				298
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	41		26		—				67
Municipal bonds	—		287		—				287
Other securities	—		228		—				228
Total debt securities	41		541		—				582
Total nuclear decommissioning trusts(2)	344		546		—				890
Short-term investments held in Rabbi Trust	64		—		—				64
Support Agreement, net of related guarantee fees	—		—		25				25
Interest rate instruments	—		293		—		$	—	293
Foreign exchange instruments	—		5		—		—		5
Commodity contracts not subject to rate recovery	—		39		—		2		41
Commodity contracts subject to rate recovery	6		1		4		18		29
Total	$	414	$	884	$	29	$	20	$	1,347
Liabilities:
Commodity contracts not subject to rate recovery	$	1	$	63	$	—	$	(38)	$	26
Commodity contracts subject to rate recovery	20		45		—		(21)		44
Total	$	21	$	108	$	—	$	(59)	$	70
	Fair value at December 31, 2023
Sempra:
Assets:
Nuclear decommissioning trusts:
Short-term investments, primarily cash equivalents	$	19	$	2	$	—			$	21
Equity securities	308		4		—				312
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	34		17		—				51
Municipal bonds	—		275		—				275
Other securities	—		220		—				220
Total debt securities	34		512		—				546
Total nuclear decommissioning trusts(2)	361		518		—				879
Short-term investments held in Rabbi Trust	67		—		—				67
Support Agreement, net of related guarantee fees	—		—		23				23
Interest rate instruments	—		87		—		$	—	87
Commodity contracts not subject to rate recovery	—		5		—		74		79
Commodity contracts subject to rate recovery	—		1		10		22		33
Total	$	428	$	611	$	33	$	96	$	1,168
Liabilities:
Foreign exchange instruments	$	—	$	9	$	—	$	—	$	9
Commodity contracts not subject to rate recovery	—		6		—		—		6
Commodity contracts subject to rate recovery	20		210		—		(19)		211
Total	$	20	$	225	$	—	$	(19)	$	226

(1)    Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

(2)    Excludes receivables (payables), net.

2024 Form 10-K | F-107

RECURRING FAIR VALUE MEASURES
(Dollars in millions)
	Level 1		Level 2		Level 3		Netting(1)		Total
	Fair value at December 31, 2024
SDG&E:
Assets:
Nuclear decommissioning trusts:
Short-term investments, primarily cash equivalents	$	8	$	2	$	—			$	10
Equity securities	295		3		—				298
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	41		26		—				67
Municipal bonds	—		287		—				287
Other securities	—		228		—				228
Total debt securities	41		541		—				582
Total nuclear decommissioning trusts(2)	344		546		—				890
Commodity contracts subject to rate recovery	4		—		4		$	17	25
Total	$	348	$	546	$	4	$	17	$	915
Liabilities:
Commodity contracts subject to rate recovery	$	18	$	1	$	—	$	(18)	$	1
	Fair value at December 31, 2023
SDG&E:
Assets:
Nuclear decommissioning trusts:
Short-term investments, primarily cash equivalents	$	19	$	2	$	—			$	21
Equity securities	308		4		—				312
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	34		17		—				51
Municipal bonds	—		275		—				275
Other securities	—		220		—				220
Total debt securities	34		512		—				546
Total nuclear decommissioning trusts(2)	361		518		—				879
Commodity contracts subject to rate recovery	—		—		10		$	21	31
Total	$	361	$	518	$	10	$	21	$	910
Liabilities:
Commodity contracts subject to rate recovery	$	20	$	—	$	—	$	(19)	$	1

(1)    Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

(2)    Excludes receivables (payables), net.

2024 Form 10-K | F-108

RECURRING FAIR VALUE MEASURES
(Dollars in millions)
	Level 1		Level 2		Level 3		Netting(1)		Total
	Fair value at December 31, 2024
SoCalGas:
Assets:
Commodity contracts subject to rate recovery	$	2	$	1	$	—	$	1	$	4
Liabilities:
Commodity contracts subject to rate recovery	$	2	$	44	$	—	$	(3)	$	43
	Fair value at December 31, 2023
SoCalGas:
Assets:
Commodity contracts subject to rate recovery	$	—	$	1	$	—	$	1	$	2
Liabilities:
Commodity contracts subject to rate recovery	$	—	$	210	$	—	$	—	$	210

(1)    Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

Level 3 Information

SDG&E

The table below sets forth reconciliations of changes in the fair value of CRRs and, until December 31, 2022, fixed-price electricity positions, classified as Level 3 in the fair value hierarchy for Sempra and SDG&E.

LEVEL 3 RECONCILIATIONS(1)
(Dollars in millions)
	2024		2023		2022
Balance at January 1	$	10	$	35	$	54
Realized and unrealized gains (losses), net	(10)		(17)		(56)
Allocated transmission instruments	3		(1)		(4)
Settlements	1		(7)		41
Balance at December 31	$	4	$	10	$	35
Change in unrealized losses relating to instruments still held at December 31	$	(4)	$	(13)	$	(10)

(1)     Excludes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.

Inputs used to determine the fair value of CRRs and fixed-price electricity positions are reviewed and compared with market conditions to determine reasonableness.

CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California ISO, an objective source. Annual auction prices are published once a year, typically in the middle of November, and are the basis for valuing CRRs settling in the following year. For the CRRs settling from January 1 to December 31, the auction price inputs, at a given location, were in the following ranges for the years indicated below:

CONGESTION REVENUE RIGHTS AUCTION PRICE INPUTS
Settlement year		Price per MWh					Median price per MWh
2025	$	(7.38)	to	$	15.54	$	0.01
2024		(3.69)	to		9.55		(0.44)
2023		(3.09)	to		10.71		(0.56)

The impact associated with discounting is not significant. Because these auction prices are a less observable input, these instruments are classified as Level 3. The fair value of these instruments is derived from auction price differences between two locations. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a significantly higher (lower) fair value measurement. We summarize CRR volumes in Note 9.

2024 Form 10-K | F-109

Long-term, fixed-price electricity positions in 2022 that were valued using significant unobservable data were classified as Level 3 because the contract terms related to a delivery location or tenor for which observable market rate information was not available. The fair value of the net electricity positions classified as Level 3 was derived from a discounted cash flow model using market electricity forward price inputs. The range and weighted-average price of these inputs at December 31, 2022 were $33.45 to $274.70 and $85.64, respectively.

Realized gains and losses associated with CRRs and long-term, fixed-price electricity positions, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations. Because unrealized gains and losses are recorded as regulatory assets and liabilities, they do not affect earnings.

Other Sempra

The table below sets forth reconciliations of changes in the fair value of Sempra’s Support Agreement for the benefit of CFIN classified as Level 3 in the fair value hierarchy.

LEVEL 3 RECONCILIATIONS
(Dollars in millions)
	2024		2023		2022
Balance at January 1	$	23	$	17	$	7
Realized and unrealized gains (losses), net(1)	11		15		19
Settlements	(9)		(9)		(9)
Balance at December 31(2)	$	25	$	23	$	17
Change in unrealized gains relating to instruments still held at December 31	$	8	$	13	$	18

(1)    Net gains are included in Interest Income and net losses are included in Interest Expense on Sempra’s Consolidated Statements of Operations.

(2)    Balance at December 31, 2024 and 2023 includes $7 in Other Current Assets, and $18 and $16, respectively, in Other Long-Term Assets on Sempra’s Consolidated Balance Sheet.

The fair value of the Support Agreement, net of related guarantee fees, is based on a discounted cash flow model using a probability of default and survival methodology. Our estimate of fair value considers inputs such as third-party default rates, credit ratings, recovery rates, and risk-adjusted discount rates, which may be readily observable, market corroborated or generally unobservable inputs. Because CFIN’s credit rating and related default and survival rates are unobservable inputs that are significant to the valuation, the Support Agreement, net of related guarantee fees, is classified as Level 3. We assigned CFIN an internally developed credit rating of A3 and relied on default rate data published by Moody’s to assign a probability of default. A hypothetical change in the credit rating up or down one notch could result in a significant change in the fair value of the Support Agreement.

2024 Form 10-K | F-110

Fair Value of Financial Instruments

The fair values of certain of our financial instruments (cash, current and noncurrent accounts receivable, amounts due to/from unconsolidated affiliates with original maturities of less than 90 days, dividends and accounts payable due in one year or less, short-term debt and customer deposits) approximate their carrying amounts because of the short-term nature of these instruments. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments that are not recorded at fair value on the Consolidated Balance Sheets.

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
	Carrying		Fair value
	amount		Level 1		Level 2		Level 3		Total
	December 31, 2024
Sempra:
Long-term note receivable(1)	$	351	$	—	$	—	$	334	$	334
Long-term amounts due to unconsolidated affiliates	352		—		324		—		324
Total long-term debt(2)	32,899		—		30,193		—		30,193
SDG&E:
Total long-term debt(3)	$	8,950	$	—	$	7,760	$	—	$	7,760
SoCalGas:
Total long-term debt(4)	$	7,359	$	—	$	6,880	$	—	$	6,880
	December 31, 2023
Sempra:
Long-term note receivable(1)	$	334	$	—	$	—	$	318	$	318
Long-term amounts due to unconsolidated affiliates	312		—		283		—		283
Total long-term debt(2)	27,716		—		25,617		—		25,617
SDG&E:
Total long-term debt(3)	$	8,750	$	—	$	7,856	$	—	$	7,856
SoCalGas:
Total long-term debt(4)	$	6,759	$	—	$	6,442	$	—	$	6,442

(1)    Before allowances for credit losses of $5 and $6 at December 31, 2024 and 2023, respectively. Excludes unamortized transaction costs of $3 and $4 at December 31, 2024 and 2023, respectively.

(2)    After the effects of interest rate swaps. Before reductions of unamortized discount and debt issuance costs of $382 and $322 at December 31, 2024 and 2023, respectively, and excluding finance lease obligations of $1,315 and $1,340 at December 31, 2024 and 2023, respectively.

(3)    Before reductions of unamortized discount and debt issuance costs of $95 and $89 at December 31, 2024 and 2023, respectively, and excluding finance lease obligations of $1,205 and $1,233 at December 31, 2024 and 2023, respectively.

(4)    Before reductions of unamortized discount and debt issuance costs of $65 and $55 at December 31, 2024 and 2023, respectively, and excluding finance lease obligations of $110 and $107 at December 31, 2024 and 2023, respectively.

We provide the fair values for the securities held in the NDT related to SONGS in Note 14.

NOTE 11. PREFERRED STOCK

Sempra and SDG&E are authorized to issue up to 50,000,000 and 45,000,000 shares of preferred stock, respectively. At December 31, 2024 and 2023, SDG&E had no preferred stock outstanding. The rights, preferences, privileges and restrictions for any new series of preferred stock would be established by each company’s board of directors at the time of issuance. We discuss SoCalGas preferred stock below.

On May 2, 2024, Sempra filed an amendment to its amended and restated articles of incorporation to implement the revocation of the series A preferred stock and series B preferred stock, all of which had previously been converted to Sempra common stock, thereby decreasing the number of authorized shares of series A preferred stock from 17,250,000 to zero and series B preferred stock from 5,750,000 to zero. Effective as of May 2, 2024, each such series of stock is no longer an authorized series of Sempra’s capital stock.

2024 Form 10-K | F-111

SEMPRA SERIES C PREFERRED STOCK

At December 31, 2024 and 2023, Sempra had 900,000 shares of 4.875% fixed-rate reset cumulative redeemable perpetual preferred stock, series C (series C preferred stock) outstanding.

Liquidation Preference

Each share of series C preferred stock has a liquidation preference of $1,000 plus any accumulated and unpaid dividends (whether or not declared) on such share.

Redemption at the Option of Sempra

The shares of series C preferred stock are perpetual and have no maturity date. However, we may, at our option, redeem the series C preferred stock in whole or in part, from time to time, on any day during the period from and including the July 15 immediately preceding October 15, 2025 and October 15 of every fifth year after 2025 through and including such October 15 at a redemption price in cash equal to $1,000 per share. Additionally, in the event that a credit rating agency then publishing a rating for us makes certain amendments, clarifications or changes to the criteria it uses to assign equity credit to securities such as the series C preferred stock (Ratings Event), we may redeem the series C preferred stock, in whole but not in part, at any time within 120 days after the conclusion of any review or appeal process instituted by us following the occurrence of the Ratings Event or, if no such review or appeal process is available or sought, the occurrence of such Ratings Event, at a redemption price in cash equal to $1,020 per share (102% of the liquidation preference per share).

Dividends

Dividends on the series C preferred stock, when, as and if declared by our board of directors or an authorized committee thereof, are payable in cash, on a cumulative basis, semi-annually in arrears. Dividends on the series C preferred stock will be cumulative whether or not:

▪we have earnings;

▪the payment of such dividends is then permitted under California law;

▪such dividends are authorized or declared; and

▪any agreements to which we are a party prohibit the current payment of dividends, including any agreement relating to our indebtedness.

We accrue dividends on the series C preferred stock on a monthly basis. The dividend rate from and including June 19, 2020 to, but excluding, October 15, 2025 is 4.875% per annum of the $1,000 liquidation preference per share. The dividend rate will reset on October 15, 2025 and on October 15 of every fifth year after 2025 and, for each five-year period following such reset dates, will be a per annum rate equal to the Five-year U.S. Treasury Rate (as defined in the certificate of determination of preferences of the series C preferred stock) as of the second business day prior to such reset date, plus a spread of 4.550%, of the $1,000 liquidation preference per share.

Voting Rights

The holders of series C preferred stock do not have any voting rights, except with respect to any authorization, creation or increase in the authorized amount of any class or series of capital stock ranking senior to the series C preferred stock, certain amendments to the terms of the series C preferred stock, in certain other limited circumstances and as otherwise specifically required by California law. In addition, whenever dividends on any shares of series C preferred stock have not been declared and paid or have been declared but not paid for three or more dividend periods, whether or not consecutive, the authorized number of directors on our board of directors will automatically be increased by two and the holders of the series C preferred stock, voting together as a single class with holders of any and all other outstanding series of preferred stock of equal rank having similar voting rights, will be entitled to elect two directors who satisfy certain requirements to fill such two newly created directorships. This voting right will terminate when all accumulated and unpaid dividends on the series C preferred stock have been paid in full and, upon such termination and the termination of the same voting rights of all other holders of outstanding series of preferred stock that have such voting rights, the term of office of each director elected pursuant to such rights will terminate and the authorized number of directors will automatically decrease by two, subject to the revesting of such rights in the event of each subsequent nonpayment.

2024 Form 10-K | F-112

Ranking

The series C preferred stock ranks, with respect to dividend rights and distribution rights upon our liquidation, winding-up or dissolution:

▪senior to our common stock and each other class or series of our capital stock established in the future, unless the terms of such capital stock expressly provide otherwise;

▪on parity with each class or series of our capital stock established in the future, if the terms of such capital stock provide that it ranks on parity with the series C preferred stock;

▪junior to each class or series of our capital stock established in the future, if the terms of such capital stock provide that it ranks senior to the series C preferred stock;

▪junior to our existing and future indebtedness and other liabilities; and

▪structurally subordinated to all existing and future indebtedness and other liabilities of our subsidiaries and capital stock of our subsidiaries held by third parties.

SOCALGAS PREFERRED STOCK

SoCalGas is authorized to issue up to an aggregate of 11,000,000 shares of preferred stock, series preferred stock and preference stock. The table below presents preferred stock outstanding at SoCalGas:

PREFERRED STOCK OUTSTANDING
(Dollars in millions, except per share amounts)
	December 31,
	2024		2023
$25 par value, authorized 1,000,000 shares:
6% Series, 79,011 shares outstanding	$	3	$	3
6% Series A, 783,032 shares outstanding	19		19
SoCalGas - Total preferred stock	22		22
Less: 50,970 shares of the 6% Series outstanding owned by Pacific Enterprises	(2)		(2)
Sempra - Total preferred stock of subsidiary	$	20	$	20

None of SoCalGas’ outstanding preferred stock is callable, and no shares are subject to mandatory redemption.

All outstanding shares have one vote per share, cumulative preferences as to dividends and liquidation preferences of $25 per share plus any unpaid dividends.

In addition to the outstanding preferred stock above, SoCalGas’ articles of incorporation authorize 5,000,000 shares of series preferred stock and 5,000,000 shares of preference stock, both without par value and with cumulative preferences as to dividends and liquidation value. The preference stock would rank junior to all series of preferred stock and series preferred stock. Other rights and privileges of any new series of such stock would be established by the SoCalGas board of directors at the time of issuance.

The preferred stock at SoCalGas is presented at Sempra as NCI. Sempra records charges against income related to NCI for preferred dividends declared by SoCalGas.

2024 Form 10-K | F-113

NOTE 12. SEMPRA – EQUITY AND EARNINGS PER COMMON SHARE

COMMON STOCK

We are authorized to issue 1,125,000,000 shares of Sempra’s no par value common stock. The following table provides common stock activity for the last three years.

COMMON STOCK ACTIVITY
	2024	2023	2022
Sempra:
Common shares outstanding, January 1	631,431,732	628,669,356	633,839,564
Shares issued under forward sale agreements	17,142,858	—	—
Shares issued to underwriters to cover overallotments	—	2,099,152	—
RSUs vesting(1)	1,320,561	941,910	914,444
Stock options exercised	143,944	—	81,260
Common stock investment plan(2)	1,151,877	1,730	—
Issuance of RSUs held in our Deferred Compensation Plan	128,207	132,178	130,026
Shares repurchased(3)	(689,303)	(412,594)	(6,295,938)
Common shares outstanding, December 31	650,629,876	631,431,732	628,669,356

(1)    Includes dividend equivalents.

(2)    Participants in the Direct Stock Purchase Plan may reinvest dividends to purchase newly issued shares.

(3)    Includes shares repurchased under repurchase programs and shares withheld from LTIP participants and individuals exercising stock options in 2024 to satisfy minimum statutory tax withholding requirements.

COMMON STOCK OFFERINGS

ATM Program

In November 2024, we established an ATM program providing for the offer and sale of shares of Sempra common stock having an aggregate gross sales price of up to $3.0 billion through agents acting as our sales agents or as forward sellers or directly to the agents as principals. The shares may be offered and sold in amounts and at times to be determined by us from time to time. The agents will be entitled to a commission that will not exceed 1.0% of the gross sales price of all shares sold through it as agent pursuant to the Sales Agreement.

Under the ATM program, we may enter into separate forward sale agreements with affiliates of the agents as forward purchasers. We expect to fully physically settle each forward sale agreement, if any. However, we will generally have the right, subject to certain exceptions, to elect to cash settle or net share settle all or any portion of our obligations under any such forward sale agreement. If we enter into a forward sale agreement with any forward purchaser, we expect that such forward purchaser (or its affiliate) will attempt to borrow from third parties and sell, through the relevant agent acting as sales agent for such forward purchaser, shares of our common stock to hedge such forward purchaser’s exposure under such forward sale agreement. We will not receive any proceeds from any sale of shares borrowed by a forward purchaser (or its affiliate) and sold through a forward seller. The forward seller will receive a commission, in the form of a reduction to the initial forward price under the related forward sale agreement, at a mutually agreed rate that will not exceed (subject to certain exceptions) 1.0% of the volume-weighted average of the gross sales price per share of all of the borrowed shares of Sempra common stock sold through such forward seller.

We intend to use a substantial portion of the net proceeds we receive from the issuance and sale by us of any shares of our common stock to or through the agents and any net proceeds we receive through the settlement of any forward sale agreements with the forward purchasers for working capital and other general corporate purposes, including to partly finance anticipated increases to our long-term capital plan and to repay outstanding commercial paper and potentially other indebtedness. At December 31, 2024, approximately $2.7 billion of common stock remained available for sale under the ATM program, which reflects the forward sale agreement that we describe below.

2024 Form 10-K | F-114

November 2024 Forward Sale Agreement

In November 2024, we entered into a forward sale agreement under the ATM program with Bank of America, N.A. as forward purchaser for the sale of 2,909,274 shares of Sempra common stock. The shares offered pursuant to the forward sale agreement were borrowed by the forward purchaser and therefore are not newly issued shares. We did not initially receive any proceeds from the sale of shares pursuant to the forward sale agreement.

At December 31, 2024, a total of 2,909,274 shares of Sempra common stock remain subject to future settlement under this forward sale agreement, which may be settled on one or more dates specified by us occurring no later than June 30, 2026, which is the final settlement date under the agreement. At the initial forward price of $92.1546 per share, we expect that the net proceeds from the full physical settlement of the forward sale agreement would be approximately $268 million (net of sales commissions of approximately $2 million, but before deducting equity issuance costs, and subject to certain adjustments pursuant to the forward sale agreements). Although we expect to settle the forward sale agreement entirely by the physical delivery of shares of our common stock in exchange for cash proceeds, we may, subject to certain conditions, elect cash settlement or net share settlement for all or a portion of our obligations under the forward sale agreement. The forward sale agreement is also subject to acceleration by the forward purchaser upon the occurrence of certain events.

November 2023 Common Stock Offering and Forward Sale Agreements

In November 2023, we completed the offering of 19,242,010 shares of our common stock, no par value, in a registered public offering at $70.00 per share ($68.845 per share after deducting underwriting discounts), 17,142,858 shares of which were pursuant to forward sale agreements with an affiliate of Morgan Stanley & Co. LLC and an affiliate of Citigroup Global Markets Inc. (the November 2023 forward purchasers). The shares offered pursuant to the forward sale agreements were borrowed by the underwriters and therefore are not newly issued shares. The underwriters of the offering partially exercised the option we granted them and purchased 2,099,152 shares of common stock directly from us solely to cover overallotments. We received net proceeds of $144 million (net of underwriting discounts and equity issuance costs of $3 million) from the sale of shares to cover overallotments. We did not initially receive any proceeds from the sale of shares pursuant to the forward sale agreements. We used the net proceeds from the sale of the overallotment shares to fund working capital and for other general corporate purposes, including to partly finance our long-term capital plan and to repay commercial paper and other indebtedness.

In December 2024, upon full physical settlement of the forward sale agreements from our November 2023 offering, we received net proceeds of $1.2 billion (net of underwriting discounts and equity issuance costs of $20 million) from the issuance of 17,142,858 shares of Sempra common stock at a forward price of $69.2195 per share. We expect to use the net proceeds from our common stock issued pursuant to the forward sale agreements to fund working capital and for other general corporate purposes, including to partly finance our long-term capital plan and to repay commercial paper and other indebtedness.

COMMON STOCK REPURCHASES

On July 6, 2020, our board of directors authorized the repurchase of shares of our common stock at any time and from time to time in an aggregate amount not to exceed the lesser of $2.0 billion or amounts spent to purchase no more than 25,000,000 shares.

On January 11, 2022, we entered into an ASR program under which we prepaid $200 million to repurchase shares of our common stock in a share forward transaction. A total of 2,945,512 shares were purchased under this program at an average price of $67.90 per share. The total number of shares purchased was determined by dividing the $200 million purchase price by the arithmetic average of the volume-weighted average trading prices of shares of our common stock during the valuation period of January 12, 2022 through February 11, 2022, minus a fixed discount. The ASR program was completed on February 11, 2022.

On April 6, 2022, we entered into an ASR program under which we prepaid $250 million to repurchase shares of our common stock in a share forward transaction. A total of 2,943,914 shares were purchased under this program at an average price of $84.92 per share. The total number of shares purchased was determined by dividing the $250 million purchase price by the arithmetic average of the volume-weighted average trading prices of shares of our common stock during the valuation period of April 7, 2022 through April 25, 2022, minus a fixed discount. The ASR program was completed on April 25, 2022.

As of February 25, 2025, a maximum of $1.25 billion and no more than 19,632,529 shares may yet be purchased under the July 6, 2020 repurchase authorization.

In 2024, 2023 and 2022, we withheld 689,303 shares for $43 million, 412,594 shares for $32 million and 406,512 shares for $28 million, respectively, of our common stock that would otherwise be issued to LTIP participants and individuals exercising stock options in 2024 who do not elect otherwise upon the vesting of RSUs and exercise of stock options in an amount sufficient to satisfy minimum statutory tax withholding requirements. Such share withholding is considered a share repurchase for accounting purposes. The repurchases do not fall under the July 6, 2020 repurchase authorization.

2024 Form 10-K | F-115

NONCONTROLLING INTERESTS

Ownership interests in a consolidated entity that are held by unconsolidated owners are accounted for and reported as NCI.

The following table summarizes net income attributable to Sempra and transfers (to) from NCI, which shows the effects of changes in Sempra’s ownership interest in its subsidiaries on Sempra’s shareholders’ equity.

NET INCOME ATTRIBUTABLE TO SEMPRA AND TRANSFERS (TO) FROM NCI
(Dollars in millions)
	Years ended December 31,
	2023		2022
Sempra:
Net income attributable to Sempra	$	3,075	$	2,139
Transfers (to) from NCI:
(Decrease) increase in shareholders’ equity for sales of NCI	(49)		710
Net transfers (to) from NCI	(49)		710
Change from net income attributable to Sempra and transfers (to) from NCI	$	3,026	$	2,849

SI Partners

Sale of NCI to ADIA

In June 2022, Sempra and ADIA consummated the transaction contemplated under a purchase and sale agreement dated December 21, 2021 (the ADIA Purchase Agreement). Pursuant to the ADIA Purchase Agreement, ADIA acquired Class A Units representing a 10% NCI in SI Partners for a purchase price of $1.7 billion, including post-closing adjustments. As a result of this sale to ADIA, we recorded a $709 million increase in equity held by NCI and an increase in Sempra’s shareholders’ equity of $710 million, net of $12 million in transaction costs and $300 million income tax expense. Transaction costs include $10 million paid to ADIA for reimbursement of certain expenses that ADIA incurred in connection with closing the transaction.

Sale of NCI to KKR Pinnacle

In connection with the October 2021 sale of NCI to KKR Pinnacle, KKR Pinnacle was entitled to a $200 million credit from Sempra to be applied to capital calls once an LNG project reached a positive final investment decision and met certain projected internal rates of return. In 2023, KKR Pinnacle used $200 million of this credit to fund its share of contributions to SI Partners. As a result, we recorded a $200 million increase in equity held by NCI and a decrease in Sempra’s shareholders’ equity of $145 million, net of a tax benefit.

SI Partners Subsidiaries

Sale of NCI to KKR Denali

In September 2023, a subsidiary of SI Partners completed the sale of a 60% interest in an SI Partners subsidiary (resulting in a 42% NCI in the PA LNG Phase 1 project) to KKR Denali for aggregate cash consideration of $976 million, including post-closing adjustments. As a result of this sale, we recorded a $1.0 billion increase in equity held by NCI and a decrease in Sempra’s shareholders’ equity of $61 million, including $11 million in transaction costs and net of a $23 million tax benefit.

SI Partners’ and KKR Denali’s subsidiaries have made capital contribution commitments to fund their respective equity share of the equity funding amount of anticipated development costs of the PA LNG Phase 1 project, except in certain budget overrun scenarios.

Sale of NCI to ConocoPhillips Affiliate

In March 2023, a subsidiary of SI Partners completed the sale of a 30% interest in an SI Partners subsidiary (resulting in a 30% NCI in the PA LNG Phase 1 project) to an affiliate of ConocoPhillips for aggregate cash consideration of $254 million, including post-closing adjustments. As a result of this sale, we recorded a $234 million increase in equity held by NCI and an increase in Sempra’s shareholders’ equity of $12 million, net of $3 million in transaction costs and $5 million in tax expense.

2024 Form 10-K | F-116

SI Partners’ subsidiary and the ConocoPhillips affiliate have made certain customary capital contribution commitments to fund their respective pro rata equity share of the total anticipated capital calls for the equity portion of the anticipated development costs of the PA LNG Phase 1 project. In addition, both SI Partners and ConocoPhillips provided guarantees relating to their respective affiliate’s commitment to make its pro rata equity share of capital contributions to fund 110% of the development budget of the PA LNG Phase 1 project, in an aggregate amount of up to $9.0 billion. SI Partners’ guarantee covers 70% of this amount plus enforcement costs of its guarantee. As of December 31, 2024, an aggregate amount of $2.7 billion has been paid by SI Partners’ subsidiary in satisfaction of its commitment to fund its portion of the development budget of the PA LNG Phase 1 project.

EARNINGS PER COMMON SHARE

Basic EPS is calculated by dividing earnings attributable to common shares by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

EARNINGS PER COMMON SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
	Years ended December 31,
	2024		2023		2022
Sempra:
Numerator:
Earnings attributable to common shares	$	2,817	$	3,030	$	2,094
Denominator:
Weighted-average common shares outstanding for basic EPS(1)	633,795		630,296		630,318
Dilutive effect of stock options and RSUs(2)	2,112		2,341		2,439
Dilutive effect of common shares sold forward	2,036		96		—
Weighted-average common shares outstanding for diluted EPS	637,943		632,733		632,757
EPS:
Basic	$	4.44	$	4.81	$	3.32
Diluted	$	4.42	$	4.79	$	3.31

(1)     Includes fully vested RSUs held in our Deferred Compensation Plan of 617 in 2024, 717 in 2023 and 805 in 2022. These fully vested RSUs are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.

(2)    Due to market fluctuations of both Sempra common stock and the comparative indices used to determine the vesting percentage of our total shareholder return performance-based RSUs, which we discuss in Note 13, dilutive RSUs may vary widely from period-to-period.

The potentially dilutive impact from stock options and RSUs is calculated under the treasury stock method. Under this method, proceeds based on the exercise price and unearned compensation are assumed to be used to repurchase shares on the open market at the average market price for the period, reducing the number of potential new shares to be issued and sometimes causing an antidilutive effect. The computation of diluted EPS for 2024, 2023 and 2022 excludes potentially dilutive shares related to stock options and RSUs of 747,724, 502,942 and 173,064, respectively, because to include them would be antidilutive for the period. However, these shares could potentially dilute basic EPS in the future.

The potentially dilutive impact from the forward sale of our common stock pursuant to the forward sale agreements that we discuss above is reflected in our diluted EPS calculation using the treasury stock method. We anticipate there will be a dilutive effect on our EPS when the average market price of our common stock shares is above the applicable adjusted forward price, subject to increase or decrease based on the overnight bank funding rate, less a spread, and subject to decrease by amounts related to expected dividends on shares of our common stock during the term of the forward sale agreements. Additionally, if we decide to physically settle or net share settle the forward sale agreements, delivery of our shares to the forward purchasers on any such physical settlement or net share settlement of the forward sale agreements would result in dilution to our EPS.

2024 Form 10-K | F-117

NOTE 13. SHARE-BASED COMPENSATION

SEMPRA EQUITY COMPENSATION PLANS

Sempra has share-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of Sempra. The plans permit a wide variety of share-based awards, including:

▪nonqualified stock options

▪incentive stock options

▪restricted stock awards

▪restricted stock units

▪stock appreciation rights

▪performance awards

▪stock payments

▪dividend equivalents

Eligible employees, including those from SDG&E and SoCalGas, participate in Sempra’s share-based compensation plans as a component of their compensation package.

In the three years ended December 31, 2024, Sempra had the following types of equity awards outstanding:

▪Nonqualified Stock Options: Options to purchase common stock have an exercise price equal to the market price of the common stock at the date of grant, are service-based, become exercisable over a three-year period and expire 10 years from the date of grant. Unvested option awards are subject to forfeiture following a termination of employment, except where the retirement criteria under such awards have been met and subject to certain other exceptions described below.

▪Performance-Based Restricted Stock Units: These RSU awards generally vest in Sempra common stock at the end of three-year performance periods based on Sempra’s total return to shareholders relative to that of specified market indices or based on the compound annual growth rate of Sempra’s EPS. The comparative market indices for the awards that vest based on total return to shareholders are the S&P 500 Utilities Index (excluding water companies) and the S&P 500 Index. Awards issued in 2024 are based on the percentile ranking of the compound annual growth rate of Sempra’s adjusted EPS relative to the compound annual growth rate of S&P 500 Utilities Index (excluding water companies) peer companies. For awards issued in 2022 and 2023, we use long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies (excluding water companies) to develop our targets for awards that vest based on EPS growth. If Sempra’s total return to shareholders or EPS growth is below the target levels but above threshold performance levels, shares are subject to partial vesting on a pro rata basis. If Sempra’s total return to shareholders or EPS growth exceeds target levels, up to an additional 100% of the granted RSUs may be issued. These RSU awards are subject to forfeiture prior to vesting following a termination of employment, except where the retirement criteria under such awards have been met and subject to certain other exceptions described below.

▪Service-Based Restricted Stock Units: RSUs may also be service-based; these generally vest ratably over three-year service periods. These awards are subject to earlier forfeiture upon termination of employment, subject to certain exceptions described below.

For awards that would otherwise be forfeited upon termination of employment, the Compensation and Talent Development Committee of Sempra’s board of directors may waive the forfeiture requirement and, with respect to options and service-based RSUs, may accelerate vesting. Awards are also subject to accelerated vesting under certain circumstances upon a change in control under the applicable LTIP, in accordance with severance pay agreements or to the extent otherwise required by the terms of the applicable award. Dividend equivalents on shares subject to RSUs are reinvested to purchase additional common shares that become subject to the same vesting conditions as the RSUs to which the dividends relate.

SHARE-BASED AWARDS AND COMPENSATION EXPENSE

At December 31, 2024, 15,400,000 common shares were authorized, and 7,628,467 common shares were available for future grants of share-based awards. Our practice is to satisfy share-based awards by issuing new shares rather than by open-market purchases.

2024 Form 10-K | F-118

We measure and recognize compensation expense for all share-based payment awards made to our employees and directors based on estimated fair values on the date of grant. We recognize compensation costs net of an estimated forfeiture rate (based on historical experience) and recognize the compensation costs for nonqualified stock options and RSUs on a straight-line basis over the requisite service period of the award, which is generally three years. However, for awards granted to retirement-eligible participants, the expense is recognized over the initial year in which the award was granted as the award requires service through the end of the year in which it was granted. For awards granted to participants who become eligible for retirement during the requisite service period, the expense is recognized over the period between the date of grant and the later of the end of the year in which the award was granted or the date the participant first becomes eligible for retirement. Substantially all awards outstanding are classified as equity instruments; therefore, we recognize additional paid in capital as we recognize the compensation expense associated with the awards. We recognize in earnings the tax benefits (or deficiencies) resulting from tax deductions that are in excess of (or less than) tax benefits related to compensation cost recognized for share-based payments.

Sempra subsidiaries record an expense for the plans to the extent that subsidiary employees participate in the plans and/or the subsidiaries are allocated a portion of the Sempra plans’ corporate staff costs. Total share-based compensation expense for all of Sempra’s share-based awards was comprised as follows:

SHARE-BASED COMPENSATION EXPENSE
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra:
Share-based compensation expense, before income taxes(1)	$	77	$	71	$	61
Income tax benefit(1)	(9)		(9)		(17)
	$	68	$	62	$	44
Capitalized share-based compensation cost	$	13	$	12	$	11
Excess income tax (benefit) deficiency	(9)		(6)		(3)
SDG&E:
Share-based compensation expense, before income taxes	$	12	$	13	$	11
Income tax benefit	(2)		(2)		(3)
	$	10	$	11	$	8
Capitalized share-based compensation cost	$	7	$	7	$	6
Excess income tax (benefit) deficiency	(1)		(1)		—
SoCalGas:
Share-based compensation expense, before income taxes	$	20	$	18	$	17
Income tax benefit	(4)		(3)		(5)
	$	16	$	15	$	12
Capitalized share-based compensation cost	$	6	$	5	$	5
Excess income tax (benefit) deficiency	(2)		(1)		—

(1)    Includes activity of awards issued from the IEnova 2013 LTIP, which settled in cash upon vesting based on the price of IEnova’s common stock.

2024 Form 10-K | F-119

SEMPRA NONQUALIFIED STOCK OPTIONS

We use a Black-Scholes option-pricing model to estimate the fair value of each nonqualified stock option grant. The use of a valuation model requires us to make certain assumptions about selected model inputs. Expected volatility is calculated based on a blend of the historical and implied volatility of Sempra’s common stock price. The average expected term for options is based on the vesting schedule, contractual term of the option, expected employee exercise and post-termination behavior. The risk-free interest rate is based on U.S. Treasury zero-coupon issues with a remaining term equal to the expected term estimated at the date of the grant. In 2024, 2023 and 2022, Sempra’s board of directors granted 414,812, 326,574 and 439,796 nonqualified stock options, respectively, that become exercisable over a three-year period. The weighted-average per-share fair value for options granted was $16.43, $17.50 and $10.99 in 2024, 2023 and 2022, respectively. To calculate this fair value, we used the Black-Scholes model with the following weighted-average assumptions:

KEY ASSUMPTIONS FOR STOCK OPTIONS GRANTED
	Years ended December 31,
	2024		2023		2022
Sempra:
Stock price volatility	26.49	%	27.35	%	26.08	%
Expected term	5.36 years		5.36 years		5.36 years
Risk-free rate of return	3.90	%	3.89	%	1.40	%
Annual dividend yield	3.14	%	2.98	%	3.33	%

The following table shows a summary of nonqualified stock options at December 31, 2024 and activity for the year then ended:

NONQUALIFIED STOCK OPTIONS
	Common shares under options	Weighted- average exercise price		Weighted- average remaining contractual term (in years)	Aggregate intrinsic value (in millions)
Sempra:
Outstanding at January 1, 2024	1,759,798	$	65.99
Granted	414,812	$	75.82
Exercised	(23,713)	$	62.87
Withheld related to net settlement	(120,231)	$	62.87
Outstanding at December 31, 2024	2,030,666	$	68.22	6.78	$	40
Vested or expected to vest at December 31, 2024	2,030,666	$	68.22	6.78	$	40
Exercisable at December 31, 2024	1,251,544	$	64.45	5.81	$	29

The aggregate intrinsic value at December 31, 2024 is the total of the difference between Sempra’s closing common stock price and the exercise price for all in-the-money options. The aggregate intrinsic value for nonqualified stock options exercised was:

▪$4.4 million in 2024

▪zero in 2023

▪$1.7 million in 2022

We expect a negligible amount of total compensation cost related to nonvested stock options not yet recognized as of December 31, 2024 to be recognized over a weighted-average period of 0.6 years. The weighted-average exercise price for nonqualified stock options granted in 2023 and 2022 was $76.86 and $66.00, respectively.

We received cash of $4 million from stock option exercises in 2022.

2024 Form 10-K | F-120

SEMPRA RESTRICTED STOCK UNITS

We use Sempra’s common stock price at the grant date to estimate the fair value of our service-based RSUs and our RSUs that vest based on the compound annual growth rate of Sempra’s EPS.

We use a Monte-Carlo simulation model to estimate the fair value of our RSUs that vest based on Sempra’s total return to shareholders. Our determination of fair value is affected by the historical volatility of the common stock price for Sempra and its peer group companies. The valuation also is affected by the risk-free rates of return and a number of other variables. Below are key assumptions for RSUs granted in the last three years:

KEY ASSUMPTIONS FOR RSUs GRANTED
	Years ended December 31,
	2024		2023		2022
Sempra:
Stock price volatility	21.27	%	35.31	%	32.82	%
Risk-free rate of return	4.06	%	4.13	%	1.05	%

The following table shows a summary of RSUs at December 31, 2024 and activity for the year then ended:

RESTRICTED STOCK UNITS
	Performance-based restricted stock units			Service-based restricted stock units
	Units	Weighted- average grant-date fair value		Units	Weighted- average grant-date fair value
Sempra:
Nonvested at January 1, 2024	1,829,984	$	74.46	524,969	$	70.63
Granted	721,049	$	75.70	321,576	$	75.86
Vested	(571,322)	$	66.52	(281,494)	$	68.68
Forfeited	(73,987)	$	76.78	(21,963)	$	88.74
Nonvested at December 31, 2024(1)	1,905,724	$	77.22	543,088	$	74.55
Expected to vest at December 31, 2024	1,865,938	$	77.19	525,029	$	74.49

(1)    Each RSU represents the right to receive one share of our common stock if applicable performance conditions are satisfied. For all performance-based RSUs, up to an additional 100% of the shares represented by the RSUs may be issued if Sempra exceeds target performance conditions.

In 2024, 2023 and 2022, the total fair value of RSU shares vested during the year was $57 million, $52 million and $54 million, respectively.

We expect $43 million of total compensation cost related to nonvested RSUs not yet recognized as of December 31, 2024 to be recognized over a weighted-average period of 1.80 years. The weighted-average per-share fair values for performance-based RSUs granted were $82.64 and $73.47 in 2023 and 2022, respectively. The weighted-average per-share fair values for service-based RSUs granted were $76.76 and $66.32 in 2023 and 2022, respectively.

2024 Form 10-K | F-121

NOTE 14. SAN ONOFRE NUCLEAR GENERATING STATION

SDG&E has a 20% ownership interest in SONGS, a nuclear generating facility near San Clemente, California, which permanently ceased operations in June 2013 after an extended outage as a result of issues with the steam generators used in the facility. Edison, the majority owner and operator of SONGS, notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the NRC to start the decommissioning activities for the entire facility. SONGS is subject to the jurisdiction of the NRC and the CPUC.

SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for financing its share of costs. SDG&E’s share of operating expenses is included in Sempra’s and SDG&E’s Consolidated Statements of Operations.

NUCLEAR DECOMMISSIONING AND FUNDING

As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison began the decommissioning phase of the plant. Major decommissioning work began in 2020. We expect the majority of the decommissioning work to be completed around 2030. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work for Unit 1 will be completed once Units 2 and 3 are dismantled and the spent fuel is removed from the site. The spent fuel is currently being stored on-site, until the DOE identifies an ISFSI and puts in place a program for the fuel’s disposal, as we discuss below. SDG&E is responsible for approximately 20% of the total decommissioning cost.

In accordance with state and federal requirements and regulations, SDG&E has assets held in the NDT to fund its share of decommissioning costs for SONGS Units 1, 2 and 3. Amounts that were collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the NDT are invested in accordance with CPUC regulations. SDG&E classifies debt and equity securities held in the NDT as available-for-sale. The NDT assets are presented on the Sempra and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities.

Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. In January 2025, the CPUC granted SDG&E authorization to access NDT funds of up to $66 million for forecasted 2025 costs.

In September 2020, the IRS and the U.S. Department of the Treasury published final regulations that clarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified trust fund. The final regulations adopted most of the provisions of the proposed regulations issued in December 2016. The final regulations apply to taxable years ending on or after September 4, 2020 and confirm that the definition of “nuclear decommissioning costs” includes amounts related to the storage of spent nuclear fuel at both on-site and off-site ISFSIs.

The final regulations also clarify that costs incurred for ISFSIs that may be or are expected to be reimbursed by the DOE may be paid or reimbursed from a qualified trust fund. Accordingly, the final regulations allow SDG&E the option to access qualified trust funds to recover spent fuel storage costs before Edison reaches final settlement with the DOE regarding the DOE’s reimbursement of these costs. Historically, the DOE’s reimbursements of spent fuel storage costs have not resulted in timely or complete recovery of these costs. We discuss the DOE’s responsibility for spent nuclear fuel below.

2024 Form 10-K | F-122

Nuclear Decommissioning Trusts

The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT on the Sempra and SDG&E Consolidated Balance Sheets. We provide additional fair value disclosures for the NDT in Note 10.

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
	Cost		Gross unrealized gains		Gross unrealized losses		Estimated fair value
	December 31, 2024
Short-term investments, primarily cash equivalents	$	10	$	—	$	—	$	10
Equity securities	78		223		(3)		298
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies(1)	67		1		(1)		67
Municipal bonds(2)	295		1		(9)		287
Other securities(3)	234		2		(8)		228
Total debt securities	596		4		(18)		582
Receivables (payables), net	(15)		—		—		(15)
Total	$	669	$	227	$	(21)	$	875
	December 31, 2023
Short-term investments, primarily cash equivalents	$	21	$	—	$	—	$	21
Equity securities	89		225		(2)		312
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	50		2		(1)		51
Municipal bonds	280		3		(8)		275
Other securities	228		3		(11)		220
Total debt securities	558		8		(20)		546
Receivables (payables), net	(7)		—		—		(7)
Total	$	661	$	233	$	(22)	$	872

(1)    Maturity dates are 2025-2055.

(2)    Maturity dates are 2025-2062.

(3)    Maturity dates are 2025-2072.

The following table shows the proceeds from sales of securities in the NDT and gross realized gains and losses on those sales.

SALES OF SECURITIES IN THE NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Proceeds from sales	$	874	$	592	$	639
Gross realized gains	57		27		18
Gross realized losses	10		14		20

Net unrealized gains and losses, as well as realized gains and losses that are reinvested in the NDT, are included in noncurrent Regulatory Liabilities on Sempra’s and SDG&E’s Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.

ASSET RETIREMENT OBLIGATION

The present value of SDG&E’s ARO related to decommissioning costs for all three SONGS units was $471 million at December 31, 2024 and is based on a cost study prepared in 2024, which is pending CPUC approval. The ARO for Units 2 and 3 reflects the acceleration of the start of decommissioning of these units as a result of the early closure of the plant. We expect SDG&E’s undiscounted SONGS decommissioning payments to be $89 million in 2025, $57 million in 2026, $37 million in 2027, $25 million in 2028, $11 million in 2029, and $870 million thereafter.

2024 Form 10-K | F-123

U.S. DEPARTMENT OF ENERGY NUCLEAR FUEL DISPOSAL

Spent nuclear fuel from SONGS is currently stored on-site in an ISFSI licensed by the NRC. The ISFSI will operate until 2054, when it is assumed that the DOE will have taken custody of all the SONGS spent fuel. The ISFSI would then be decommissioned, and the site restored to its original environmental state. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS.

The Nuclear Waste Policy Act of 1982 made the DOE responsible for accepting, transporting, and disposing of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay will lead to increased costs for spent fuel storage. In November 2019, Edison filed a claim for spent fuel management costs in the U.S. Court of Federal Claims for the time period from January 2017 through July 2018, which is pending approval. Additionally, in July 2024, Edison filed a claim for spent fuel management costs in the U.S. Court of Federal Claims for the time period from August 2018 through December 2021, which is pending approval. SDG&E will continue to support Edison in its pursuit of claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel.

NUCLEAR INSURANCE

SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. Currently, this insurance provides $500 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides an additional $60 million of coverage. If a nuclear liability loss occurs at SONGS and exceeds the $500 million insurance limit, this additional coverage would be available to provide a total of $560 million in coverage limits per incident.

The SONGS owners have nuclear property damage insurance of $130 million, which exceeds the minimum federal requirement of $50 million. This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed a negligible amount for retrospective premiums based on overall member claims.

The nuclear property insurance program includes an industry aggregate loss limit for non-certified acts of terrorism (as defined by the Terrorism Risk Insurance Act) of $3.24 billion. This is the maximum amount that will be paid to insured members who suffer losses or damages from these non-certified terrorist acts.

NOTE 15. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

We accrue losses for a legal proceeding when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. However, the uncertainties inherent in legal proceedings make it difficult to reasonably estimate the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed, and in some cases have exceeded, applicable insurance coverage and could materially adversely affect our business, results of operations, financial condition, cash flows and/or prospects. Unless otherwise indicated, we are unable to reasonably estimate possible losses or a range of losses in excess of any amounts accrued.

At December 31, 2024, loss contingency accruals for legal matters that are probable and estimable were $41 million for Sempra, including $26 million for SoCalGas. We discuss our policy regarding accrual of legal fees in Note 1.

2024 Form 10-K | F-124

SDG&E

City of San Diego Franchise Agreement

In 2021, two lawsuits were filed in the California Superior Court challenging various aspects of the natural gas and electric franchise agreements granted by the City of San Diego to SDG&E. Both lawsuits ultimately sought to void the franchise agreements. In one of the cases, judgment was granted in favor of SDG&E and the City of San Diego. In November 2024, the Court of Appeal affirmed the trial court judgment in favor of SDG&E and the City of San Diego. The plaintiff in that case has further appealed. In the second case, the court ruled in favor of SDG&E and the City of San Diego, upholding all terms of the franchise agreements, except for the two-thirds City Council vote requirement for termination if the City decides to terminate under certain circumstances. Under the court’s ruling, the City can instead terminate on a majority vote, so long as it satisfies repayment provisions under the franchise agreements. Both sides have appealed the ruling.

SoCalGas

Aliso Canyon Natural Gas Storage Facility Gas Leak

From October 23, 2015 through February 11, 2016, SoCalGas experienced a natural gas leak from one of the injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility in Los Angeles County.

In September 2021, SoCalGas and Sempra entered into an agreement with counsel to resolve approximately 390 lawsuits including approximately 36,000 plaintiffs (the Individual Plaintiffs) then pending against SoCalGas and Sempra related to the Leak for a payment of up to $1.8 billion. Over 99% of the Individual Plaintiffs participated and submitted valid releases, and SoCalGas paid $1.79 billion in 2022 under the agreement. The Individual Plaintiffs who did not participate in the settlement (the Non-Settling Individual Plaintiffs) are able to continue to pursue their claims. As of February 19, 2025, there are approximately 520 plaintiffs who are either new plaintiffs or Non-Settling Individual Plaintiffs.

The new plaintiffs’ cases and Non-Settling Individual Plaintiffs’ cases are coordinated before a single court in the Los Angeles County Superior Court for pretrial management under a consolidated master complaint filed in November 2017, with one plaintiff’s case proceeding under a separate complaint. Both the consolidated master complaint and the separate complaint assert negligence, negligence per se, strict liability, negligent and intentional infliction of emotional distress and fraudulent concealment. The consolidated master complaint asserts additional causes of action for private and public nuisance (continuing and permanent), trespass, inverse condemnation, loss of consortium and wrongful death against SoCalGas and Sempra. The separate complaint asserts an additional cause of action for assault and battery. Both complaints seek compensatory and punitive damages for personal injuries, lost wages and/or lost profits, costs of future medical monitoring, and attorneys’ fees. The consolidated master complaint also seeks property damage and diminution in property value, injunctive relief and civil penalties.

SoCalGas recorded total charges of $259 million ($199 million after tax) in the year ended December 31, 2022 in Aliso Canyon Litigation and Regulatory Matters on the SoCalGas and Sempra Consolidated Statements of Operations related to the litigation and regulatory proceedings associated with the Leak.

Aliso Canyon Natural Gas Storage Facility Regulatory Proceeding – Resolved

In February 2017, the CPUC opened proceeding SB 380 OII to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility while still maintaining energy and electric reliability for the region, but excluding issues with respect to air quality, public health, causation, culpability or cost responsibility regarding the Leak. The first phase of the proceeding established a framework for the hydraulic, production cost and economic modeling assumptions for the potential reduction in usage or elimination of the Aliso Canyon natural gas storage facility, as well as evaluating the impacts of reducing or eliminating the Aliso Canyon natural gas storage facility using the established framework and models. The next phase of the proceeding included engaging a consultant to analyze alternative means for meeting or avoiding the demand for the facility’s services if it were eliminated in either the 2027 or 2035 timeframe, and to address potential implementation of alternatives to the Aliso Canyon natural gas storage facility if the CPUC determines that the Aliso Canyon natural gas storage facility should be permanently closed. The CPUC also added all California IOUs as parties to the proceeding and encouraged all load-serving entities in the Los Angeles Basin to join the proceeding.

In December 2024, the CPUC approved an FD in the SB 380 OII finding that the Aliso Canyon natural gas storage facility is currently necessary for natural gas and electric reliability and affordable rates and closed the OII. Among other things, and subject to future CPUC biennial reviews and potential additional proceedings, the FD authorizes the Aliso Canyon natural gas storage facility to continue operating and sets the maximum working natural gas storage level at 68.6 bcf.

2024 Form 10-K | F-125

Other Sempra

Energía Costa Azul

We describe below certain land disputes and permit challenges affecting our ECA Regas Facility. Certain of these land disputes involve land on which portions of the ECA LNG liquefaction facilities under construction and in development are expected to be situated or on which portions of the ECA Regas Facility that would be necessary for the operation of such ECA LNG liquefaction facilities are situated. One or more unfavorable final decisions on these disputes or challenges could materially adversely affect our existing natural gas regasification operations and proposed natural gas liquefaction projects at the site of the ECA Regas Facility and have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.

Land Disputes. Sempra Infrastructure has been engaged in a long-running land dispute with a claimant relating to property adjacent to its ECA Regas Facility that allegedly overlaps with land owned by the ECA Regas Facility (the facility, however, is not situated on the land that is the subject of this dispute), as follows:

▪The claimant to the adjacent property filed complaints in the federal Agrarian Court challenging the refusal of SEDATU in 2006 to issue title to him for the disputed property. In November 2013, the federal Agrarian Court ordered that SEDATU issue the requested title to the claimant and cause it to be registered. Both SEDATU and Sempra Infrastructure challenged the ruling due to lack of notification of the underlying process. In May 2019, a federal court in Mexico reversed the ruling and ordered a retrial. In November 2024, the plaintiff withdrew the lawsuit and the case was dismissed, definitively resolving this matter.

▪In a separate proceeding, the claimant filed suit to reinitiate an administrative procedure at SEDATU to obtain the property title that, as described above, had previously been issued in a ruling by the federal Agrarian Court and subsequently reversed by a federal court in Mexico. In April 2021, the proceeding in the Agrarian Court concluded with the court ordering that the administrative procedure be restarted. The administrative procedure at SEDATU may continue if SEDATU decides to reopen the matter.

In addition, a plaintiff filed a claim in the federal Agrarian Court that seeks to annul the property title for a portion of the land on which the ECA Regas Facility is situated and to obtain possession of a different parcel that allegedly overlaps with the site of the ECA Regas Facility. The proceeding, which seeks an order that SEDATU annul the ECA Regas Facility’s competing property title, was initiated in 2006 and, in July 2021, a decision was issued in favor of the ECA Regas Facility. The plaintiff appealed and, in February 2022, the appellate court confirmed the ruling in favor of the ECA Regas Facility and dismissed the appeal. The plaintiff filed a federal appeal against the appellate court ruling. In August 2024, the Federal Collegiate Circuit Court ruled in favor of the ECA Regas Facility. In November 2024, the plaintiff filed an appeal with the Mexican Supreme Court.

Environmental and Social Impact Permits. Several administrative challenges are pending before Mexico’s Secretariat of Environment and Natural Resources (the Mexican environmental protection agency) and Federal Tax and Administrative Courts, seeking revocation of the environmental impact authorization issued to the ECA Regas Facility in 2003. These cases generally allege that the conditions and mitigation measures in the environmental impact authorization are inadequate and challenge findings that the activities of the terminal are consistent with regional development guidelines.

In 2018 and 2021, three related claimants filed separate challenges in the federal district court in Ensenada, Baja California seeking revocation of the environmental and social impact permits issued by each of ASEA and SENER to ECA LNG authorizing natural gas liquefaction activities at the ECA Regas Facility, as follows:

▪In the first case, the court issued a provisional injunction against the permits in September 2018. In December 2018, ASEA approved modifications to the environmental permit that facilitate the development of the proposed natural gas liquefaction facility in two phases. In May 2019, the court canceled the provisional injunction. The claimant appealed the court’s decision to cancel the injunction but was not successful. The lower court’s ruling was favorable to the ECA Regas Facility, as the court determined that no harm has been caused to the plaintiff and dismissed the lawsuit. The claimant appealed and the appellate court’s ruling is pending.

▪In the second case, the initial request for a provisional injunction against the permits was denied. That decision was reversed on appeal in January 2020, resulting in the issuance of a new injunction against the permits that were issued by ASEA and SENER. This injunction has uncertain application absent clarification by the court. The claimants petitioned the court to rule that construction of natural gas liquefaction facilities violated the injunction and, in February 2022, the court ruled in favor of the ECA Regas Facility, holding that the natural gas liquefaction construction activities did not violate the injunction. The claimants appealed this ruling but were not successful. The lower court’s ruling was favorable to the ECA Regas Facility, as the court determined that no harm has been caused to the plaintiffs and dismissed the lawsuit. The claimants appealed and the appellate court’s ruling is pending.

2024 Form 10-K | F-126

▪In the third case, a group of residents filed a complaint in June 2021 against various federal and state authorities alleging deficiencies in the public consultation process for the issuance of the permits. The request for an initial injunction was denied. The claimants appealed this ruling but were not successful. The lower court’s ruling was favorable to the ECA Regas Facility, as the court determined that no harm has been caused to the plaintiffs and dismissed the lawsuit. The claimants appealed and the appellate court’s ruling is pending.

Port Arthur LNG

The PA LNG Phase 1 project holds two Clean Air Act Prevention of Significant Deterioration permits issued by the TCEQ, which we refer to as the “2016 Permit” and the “2022 Permit.” The 2022 Permit also governs emissions for the proposed PA LNG Phase 2 project. In November 2023, a panel of the U.S. Court of Appeals for the Fifth Circuit issued a decision to vacate and remand the 2022 Permit to the TCEQ for additional explanation of the agency’s permit decision. In February 2024, the court withdrew its opinion and referred the case to the Supreme Court of Texas to resolve the question of the appropriate standard to be applied by the TCEQ. In February 2025, the Supreme Court of Texas adopted Port Arthur LNG’s interpretation of the standard. Port Arthur LNG continues to litigate this matter before the U.S. Court of Appeals for the Fifth Circuit, which will apply the standard adopted by the Supreme Court of Texas. The 2022 Permit is effective during the pending litigation. The 2016 Permit was not the subject of, and is unaffected by, the pending litigation of the 2022 Permit. Construction of the PA LNG Phase 1 project is proceeding uninterrupted under existing permits, and we do not currently anticipate the pending litigation to materially impact the PA LNG Phase 1 project cost, schedule or expected commercial operations at this stage.

Litigation Related to Regulatory and Other Actions by the Mexican Government

Amendments to Mexico’s Electricity Industry Law. In March 2021, the Mexican government published a decree with amendments to Mexico’s Electricity Industry Law that include some public policy changes, including establishing priority of dispatch for CFE plants over privately owned plants. The decree further purports to permit the CRE to revoke self-supply permits granted under the former electricity law, which were grandfathered when the new Electricity Industry Law was enacted, if it considers them to have been obtained improperly. According to the decree, these amendments were to become effective in March 2021, and SENER, the CRE and Centro Nacional de Control de Energía (Mexico’s National Center for Energy Control) were to have 180 calendar days to modify, as necessary, all resolutions, policies, criteria, manuals and other regulations applicable to the power industry to conform with this decree. Numerous legal actions were taken against the decree, which resulted in Mexican courts issuing a suspension of the decree later in March 2021.

In April 2022, the Mexican Supreme Court resolved an action of unconstitutionality filed by a group of senators against the amended Electricity Industry Law. The super majority needed to find the amendment unconstitutional was not reached and the proceeding was therefore dismissed, leaving the amended Electricity Industry Law in place. However, the Court nevertheless found certain of the amendments, including the priority of dispatch for the CFE and other provisions that granted preference to the CFE over private companies, were invalid.

In January 2024, the Second Chamber of the Mexican Supreme Court definitively resolved an amparo in a separate case brought by a third party and ruled that certain provisions of the amendments of the Electricity Industry Law are unconstitutional, including the priority of dispatch for the CFE and other provisions that granted preference to the CFE over private companies. The Court also dismissed an amparo relating to the provision of the decree applicable to self-supply permits granted under the former electricity law, and established that its decision applies generally over all participants.

Sempra Infrastructure filed three lawsuits challenging the amendments to the Electricity Industry Law, including one concerning the provision permitting revocation of self-supply permits deemed improperly obtained. In each of them, Sempra Infrastructure obtained a favorable judgment in the lower court, all of which were challenged by the CRE. Following the criteria established by the Mexican Supreme Court, in July 2024, the Second Collegiate Court reversed the lower court’s decision and definitively dismissed one of the lawsuits filed by Sempra Infrastructure regarding the provision permitting revocation of self-supply permits. Consequently, the CRE may be required to seek to revoke such self-supply permits, under a legal standard that is ambiguous and not well defined under the law. Sempra Infrastructure supplies power pursuant to self-supply permits, and would be permitted to file amparos challenging the constitutionality of any such action. If such self-supply permits are revoked, it may result in increased costs for Sempra Infrastructure and for its power consumers, adversely affect our ability to develop new projects, result in decreased revenues and cash flows, and negatively impact our ability to recover the carrying values of our investments in Mexico, any of which could have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects. Final resolution regarding the two remaining lawsuits is still pending.

2024 Form 10-K | F-127

RBS Sempra Commodities LLP – Resolved

As we discuss in Note 5, Sempra held an equity method investment in RBS Sempra Commodities LLP, a limited liability partnership that was substantially liquidated in 2024. In 2015, liquidators filed a claim in the High Court of Justice against The Royal Bank of Scotland plc (now NatWest Markets plc, our partner in the JV) and Mercuria Energy Europe Trading Limited (the Defendants) on behalf of 10 companies (the Liquidating Companies) that engaged in carbon credit trading via chains that included a company that traded directly with RBS Sempra Energy Europe, a subsidiary of RBS Sempra Commodities LLP. The claim alleged that the Defendants’ participation in the purchase and sale of carbon credits resulted in the Liquidating Companies’ carbon credit trading transactions creating a VAT liability they were unable to pay, and that the Defendants were liable to provide for equitable compensation due to dishonest assistance and compensation under the U.K. Insolvency Act of 1986. Trial on the matter was held in 2018. In March 2020, the High Court of Justice rendered its judgment mostly in favor of the Liquidating Companies. The Defendants appealed and, in May 2021, the Court of Appeal set aside the High Court of Justice’s decision and ordered a retrial. In July 2022, the Supreme Court of the U.K. denied the Liquidating Companies application for permission to appeal the Court of Appeal’s decision. In January 2024, the parties settled the Liquidating Companies’ claim against the Defendants, which fully resolved these matters.

Ordinary Course Litigation

We are also defendants in ordinary routine litigation incidental to our businesses, including personal injury, employment litigation, product liability, property damage and other claims. Juries have demonstrated an increasing willingness to grant large awards, including punitive damages, in these types of cases.

LEASES

A lease exists when a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. We determine if an arrangement is or contains a lease at inception of the contract.

Some of our lease agreements contain nonlease components, which represent activities that transfer a separate good or service to the lessee. As the lessee for both operating and finance leases, we have elected to combine lease and nonlease components as a single lease component for real estate, fleet vehicles, aircraft, power generating facilities and pipelines, whereby fixed or in-substance fixed payments allocable to the nonlease component are accounted for as part of the related lease liability and ROU asset. As the lessor, we have elected to combine lease and nonlease components as a single lease component for refined products terminals if the timing and pattern of transfer of the lease and nonlease components are the same and the lease component would be classified as an operating lease if accounted for separately.

Lessee Accounting

We have operating and finance leases for real and personal property (including office space, land, fleet vehicles, aircraft, tugboats, machinery and equipment, warehouses and other operational facilities) and PPAs with renewable energy, energy storage and peaker plant facilities.

Some of our leases include options to extend the lease terms for up to 25 years, or to terminate the lease within one year. Our lease liabilities and ROU assets are based on lease terms that may include such options when it is reasonably certain that we will exercise the option.

Certain of our contracts are short-term leases, which have a lease term of 12 months or less at lease commencement. We do not recognize a lease liability or ROU asset arising from short-term leases for all existing classes of underlying assets. In such cases, we recognize short-term lease costs on a straight-line basis over the lease term. Our short-term lease costs for the period reasonably reflect our short-term lease commitments.

Certain of our leases contain escalation clauses requiring annual increases in rent ranging from 2% to 5% or based on the Consumer Price Index. The rentals payable under these leases may increase by a fixed amount each year or by a percentage of a base year. Variable lease payments that are based on an index or rate are included in the initial measurement of our lease liability and ROU asset based on the index or rate at lease commencement and are not remeasured because of changes to the index or rate. Rather, changes to the index or rate are treated as variable lease payments and recognized in the period in which the obligation for those payments is incurred.

Similarly, PPAs for the purchase of renewable energy at SDG&E require lease payments based on a stated rate per MWh produced by the facilities, and we are required to purchase substantially all the output from the facilities. SDG&E is required to pay additional amounts for capacity charges and actual purchases of energy that exceed the minimum energy commitments. Under these contracts, we do not recognize a lease liability or ROU asset for leases for which there are no fixed lease payments.

2024 Form 10-K | F-128

Rather, these variable lease payments are recognized separately as variable lease costs. SDG&E estimates these variable lease payments to be $296 million in 2025, $290 million in 2026, $289 million in 2027, $290 million in 2028, $289 million in 2029 and $1.9 billion thereafter.

As of the lease commencement date, we recognize a lease liability for our obligation to make future lease payments, which we initially measure at present value using our incremental borrowing rate at the date of lease commencement, unless the rate implicit in the lease is readily determinable. We determine our incremental borrowing rate based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We also record a corresponding ROU asset, initially equal to the lease liability and adjusted for lease payments made at or before lease commencement, lease incentives, and any initial direct costs. We test ROU assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of the ROU assets.

For our operating leases, our non-regulated entities recognize a single lease cost on a straight-line basis over the lease term in operating expenses. SDG&E and SoCalGas recognize this single lease cost on a basis that is consistent with the recovery of such costs in accordance with U.S. GAAP governing rate-regulated operations.

For our finance leases, the interest expense on the lease liability and amortization of the ROU asset are accounted for separately. Our non-regulated entities use the effective interest rate method to account for the imputed interest on the lease liability and amortize the ROU asset on a straight-line basis over the lease term. SDG&E and SoCalGas recognize amortization of the ROU asset on a basis that is consistent with the recovery of such costs in accordance with U.S. GAAP governing rate-regulated operations.

Our leases do not contain any material residual value guarantees, restrictions or covenants.

2024 Form 10-K | F-129

Classification of ROU assets and lease liabilities and the weighted-average remaining lease term and discount rate associated with operating and finance leases are summarized in the table below.

LESSEE INFORMATION ON THE CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	Sempra						SDG&E						SoCalGas
	December 31,
	2024			2023			2024			2023			2024			2023
ROU assets:
Operating leases:
ROU assets	$	1,177		$	723		$	795		$	368		$	18		$	29
Finance leases:
PP&E	1,626			1,585			1,426			1,412			200			173
Accumulated depreciation	(311)			(246)			(221)			(179)			(90)			(66)
PP&E, net	1,315			1,339			1,205			1,233			110			107
Total ROU assets	$	2,492		$	2,062		$	2,000		$	1,601		$	128		$	136
Lease liabilities:
Operating leases:
Other current liabilities(1)	$	91		$	70		$	68		$	50		$	8		$	10
Deferred credits and other(2)	1,019			599			734			325			9			18
	1,110			669			802			375			17			28
Finance leases:
Current portion of long-term debt and finance leases	65			64			42			41			23			23
Long-term debt and finance leases	1,250			1,276			1,163			1,192			87			84
	1,315			1,340			1,205			1,233			110			107
Total lease liabilities	$	2,425		$	2,009		$	2,007		$	1,608		$	127		$	135
Weighted-average remaining lease term (in years):
Operating leases	13			13			12			10			2			3
Finance leases	14			15			15			16			6			6
Weighted-average discount rate:
Operating leases(3)	6.10		%	6.64		%	5.06		%	4.52		%	4.70		%	4.54		%
Finance leases	13.71		%	13.80		%	14.11		%	14.18		%	5.35		%	4.94		%

(1)    Includes $43 and $18 related to PPAs at December 31, 2024 and 2023, respectively, at both Sempra and SDG&E.

(2)    Includes $627 and $208 related to PPAs at December 31, 2024 and 2023, respectively, at both Sempra and SDG&E.

(3)    Weighted-average discount rate related to PPAs at December 31, 2024 and 2023 is 5.04% and 4.19%, respectively, at both Sempra and SDG&E. Weighted-average discount rate related to all other operating leases at December 31, 2024 and 2023 is 7.41% and 7.57%, respectively, at Sempra and 5.23% and 5.06%, respectively, at SDG&E.

2024 Form 10-K | F-130

The components of lease costs were as follows:

LESSEE INFORMATION ON THE CONSOLIDATED STATEMENTS OF OPERATIONS(1)
(Dollars in millions)
	Sempra						SDG&E						SoCalGas
	Years ended December 31,
	2024		2023		2022		2024		2023		2022		2024		2023		2022
Operating lease costs(2)	$	118	$	99	$	83	$	71	$	53	$	45	$	12	$	13	$	18
Finance lease costs:
Amortization of ROU assets(3)	65		60		48		42		40		33		23		20		15
Interest on lease liabilities	178		182		184		173		177		181		6		5		2
Total finance lease costs	243		242		232		215		217		214		29		25		17
Short-term lease costs(4)	9		9		3		8		8		2		—		—		—
Variable lease costs(4)	472		458		411		460		447		399		10		10		11
Total lease costs	$	842	$	808	$	729	$	754	$	725	$	660	$	51	$	48	$	46

(1)    Includes costs capitalized in PP&E.

(2)    Includes $37, $21, and $10 related to PPAs in 2024, 2023 and 2022, respectively, at both Sempra and SDG&E.

(3)    Included in O&M, except for $30, $29 and $25 at Sempra and $29, $28 and $24 at SDG&E in 2024, 2023 and 2022, respectively, and $1 at SoCalGas in each of 2024, 2023 and 2022, which is included in Depreciation and Amortization Expense.

(4)    Short-term leases with variable lease costs are recorded and presented as variable lease costs.

Cash paid for amounts included in the measurement of lease liabilities and supplemental noncash information were as follows:

LESSEE INFORMATION ON THE CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Sempra						SDG&E						SoCalGas
	Years ended December 31,
	2024		2023		2022		2024		2023		2022		2024		2023		2022
Operating activities:
Cash paid for operating leases	$	112	$	85	$	88	$	70	$	46	$	45	$	12	$	13	$	18
Cash paid for finance leases	163		167		169		158		162		166		6		5		2
Financing activities:
Cash paid for finance leases	66		60		48		42		40		33		24		20		15
Increase in operating lease obligations for ROU assets	520		143		142		474		134		134		—		—		1
Increase in finance lease obligations for investment in PP&E	41		57		57		14		17		16		27		40		41

2024 Form 10-K | F-131

The table below presents the maturity analysis of our lease liabilities and reconciliation to the present value of lease liabilities at December 31, 2024:

LESSEE MATURITY ANALYSIS OF LIABILITIES
(Dollars in millions)
	Sempra				SDG&E				SoCalGas
	Operating leases(1)		Finance leases		Operating leases(1)		Finance leases(2)		Operating leases		Finance leases
2025	$	142	$	224	$	97	$	196	$	10	$	28
2026	142		220		98		195		7		25
2027	134		218		97		194		—		24
2028	128		212		92		193		—		19
2029	124		204		89		190		—		14
Thereafter	966		1,745		571		1,727		—		18
Total undiscounted lease payments	1,636		2,823		1,044		2,695		17		128
Less: imputed interest	(526)		(1,508)		(242)		(1,490)		—		(18)
Total lease liabilities	1,110		1,315		802		1,205		17		110
Less: current lease liabilities	(91)		(65)		(68)		(42)		(8)		(23)
Long-term lease liabilities	$	1,019	$	1,250	$	734	$	1,163	$	9	$	87

(1)    Includes $76 in 2025, $75 in 2026, $76 in 2027, $75 in each of 2028 and 2029, and $525 thereafter related to PPAs.

(2)     Substantially all amounts are related to PPAs.

Leases That Have Not Yet Commenced

SDG&E has entered into four PPAs, of which SDG&E expects two will commence in 2025 and two will commence in 2026. SDG&E expects the future minimum lease payments to be $16 million in 2025, $41 million in 2026, $43 million each of 2027 through 2029 and $459 million thereafter (through expiration in 2041).

SoCalGas has entered into a lease agreement for a new headquarters office space in Los Angeles that it expects will commence in 2026. In 2024, SoCalGas prepaid $1 million and expects the future minimum lease payments to be $8 million in 2028, $9 million in 2029 and $134 million thereafter (through expiration in 2041).

Sempra Infrastructure has entered into a lease agreement for tugboat services for the PA LNG Phase 1 project that it expects will commence in 2027. Sempra Infrastructure expects the future minimum lease payments to be $10 million in 2027, $12 million, in each of 2028 and 2029 and $198 million thereafter (through expiration in 2047, exclusive of certain renewal options) and total future minimum fixed payments for operation and maintenance services to be $184 million.

Lessor Accounting

Sempra Infrastructure is a lessor for certain of its natural gas and ethane pipelines, compressor stations, LPG storage facilities, a rail facility and refined products terminals, which we account for as operating or sales-type leases. These leases expire at various dates from 2025 through 2042.

Over the lease term, we monitor the underlying assets in operating leases for impairment, and we evaluate the net investment in sales-type leases for expected credit losses. Sempra Infrastructure expects to continue to derive value from the underlying assets associated with its pipelines following the end of their respective lease terms based on the expected remaining useful life, expected market conditions and plans to re-market and re-contract the underlying assets.

Generally, we recognize operating lease income on a straight-line basis over the lease term, and sales-type lease income based on the effective interest method over the lease term. Certain of our leases contain rate adjustments or are based on foreign currency exchange rates that may result in lease payments received that vary in amount from one period to the next. In addition to minimum fixed payments, our refined products terminals receive variable lease payments for barrels delivered that exceed minimum delivery requirements.

2024 Form 10-K | F-132

LESSOR INFORMATION
(Dollars in millions)
	December 31,
	2024		2023
Sempra – Assets subject to operating leases:
Property, plant and equipment:
Pipelines and storage	$	1,313	$	1,304
Refined products terminals	623		621
Other	77		77
Total	2,013		2,002
Accumulated depreciation	(605)		(539)
Property, plant and equipment, net	$	1,408	$	1,463
	December 31, 2024
Sempra – Maturity analysis of lease payments:	Operating leases		Sales-type leases
2025	$	318	$	17
2026	272		9
2027	269		—
2028	268		—
2029	246		—
Thereafter	2,324		—
Total undiscounted cash flows	$	3,697	26
Less: present value of lease payments (recognized as lease receivable)(1)			(23)
Difference between undiscounted cash flows and discounted cash flows			$	3

(1)     Includes $15 in Other Current Assets and $8 in Other Long-Term Assets on the Consolidated Balance Sheet.

LESSOR INFORMATION ON THE CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra – Sales-type leases:
Interest income	$	5	$	6	$	8
Total revenues from sales-type leases(1)	$	5	$	6	$	8
Sempra – Operating leases:
Fixed lease payments	$	340	$	321	$	290
Variable lease payments	38		34		10
Total revenues from operating leases(1)	$	378	$	355	$	300
Depreciation expense	$	73	$	62	$	54

(1)     Included in Revenues: Energy-Related Businesses on the Consolidated Statements of Operations.

CONTRACTUAL COMMITMENTS

Natural Gas Contracts

SoCalGas procures natural gas for both SDG&E’s and SoCalGas’ core customers in a combined portfolio. SoCalGas buys natural gas under short-term and long-term contracts for this portfolio from various producing regions in the southwestern U.S., U.S. Rockies and Canada.

SoCalGas transports natural gas primarily under long-term firm interstate pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates. SoCalGas has commitments with interstate pipeline companies for firm pipeline capacity under contracts that expire at various dates through 2032.

Sempra has various capacity agreements for natural gas storage and transportation that expire at various dates through 2059. Transportation costs on these agreements vary based on pipeline capacity.

2024 Form 10-K | F-133

Payments on our natural gas contracts could exceed the minimum commitment based on portfolio needs. At December 31, 2024, the future minimum payments under existing natural gas contracts and natural gas storage and transportation contracts are as follows:

FUTURE MINIMUM PAYMENTS
(Dollars in millions)
	Sempra						SoCalGas
	Storage and transportation		Natural gas(1)		Total(1)		Transportation		Natural gas		Total
2025	$	229	$	65	$	294	$	130	$	61	$	191
2026	225		175		400		125		108		233
2027	203		271		474		104		124		228
2028	155		242		397		71		83		154
2029	140		152		292		59		—		59
Thereafter	1,283		212		1,495		118		—		118
Total minimum payments	$	2,235	$	1,117	$	3,352	$	607	$	376	$	983

(1)    Excludes amounts related to the LNG purchase agreement that we discuss below.

Total payments under natural gas contracts and natural gas storage and transportation contracts as well as payments to meet additional portfolio needs at Sempra and SoCalGas were as follows:

PAYMENTS UNDER NATURAL GAS CONTRACTS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra	$	1,185	$	4,030	$	2,536
SoCalGas	1,088		3,857		2,492

LNG Purchase Agreement

Sempra Infrastructure has an SPA for the supply of LNG to the ECA Regas Facility. The commitment amount is calculated using a predetermined formula based on estimated forward prices of the index applicable from 2025 to 2029. Although this agreement specifies a number of cargoes to be delivered, under its terms, the supplier may divert certain cargoes, which would reduce amounts paid under the agreement by Sempra Infrastructure.

At December 31, 2024, the following LNG commitment amounts are based on the assumption that all LNG cargoes under the agreement are delivered, less those already confirmed to be diverted as of December 31, 2024.

LNG COMMITMENT AMOUNTS
(Dollars in millions)
Sempra:
2025	$	355
2026	640
2027	657
2028	646
2029	402
Total	$	2,700

Actual LNG purchases were approximately $23 million in 2024, $30 million in 2023 and $108 million in 2022 due to the supplier electing to divert cargoes as allowed by the agreement.

2024 Form 10-K | F-134

PPAs Not Accounted for as Leases

Payments on SDG&E’s PPAs could exceed the minimum commitments based on energy needs. These PPAs expire on various dates through 2041. At December 31, 2024, the future minimum payments under long-term PPAs for Sempra and SDG&E are as follows:

FUTURE MINIMUM PAYMENTS(1)
(Dollars in millions)
2025	$	97
2026	116
2027	114
2028	114
2029	114
Thereafter	746
Total minimum payments	$	1,301

(1)    Excludes PPAs accounted for as operating leases and finance leases.

Payments on these contracts represent capacity charges and minimum energy and transmission purchases that exceed the minimum commitment. SDG&E is required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. SDG&E estimates these variable payments to be $79 million in each of 2025 and 2026, $80 million in each of 2027 through 2029 and $440 million thereafter. Total fixed and variable payments under PPAs not accounted for as leases for Sempra and SDG&E were $326 million in 2024, $325 million in 2023 and $297 million in 2022.

Construction and Development Projects

SDG&E

At December 31, 2024, SDG&E has commitments to make future payments of $133 million for construction projects that include:

▪$100 million related to construction supply agreements;

▪$19 million related to spent fuel management at SONGS; and

▪$14 million for infrastructure improvements for electric transmission and distribution systems.

SDG&E expects future payments under these contractual commitments to be $115 million in 2025, $1 million in each of 2026 through 2028, $2 million in 2029 and $13 million thereafter.

OTHER COMMITMENTS

SDG&E

We discuss nuclear insurance and nuclear fuel disposal related to SONGS in Note 14.

Fire Mitigation Fund

In connection with the completion of the Sunrise Powerlink project in 2012, the CPUC required that SDG&E establish a fire mitigation fund to minimize the risk of fire as well as reduce the potential wildfire impact on residences and structures near the Sunrise Powerlink. The future payments for these contractual commitments, for which a liability has been recorded, are expected to be $4 million per year in 2025 through 2029 and $264 million thereafter, subject to escalation of 2% per year, ending in 2069. At December 31, 2024, the present value of these future payments of $124 million has been recorded as a regulatory asset as the amounts represent a cost that we expect will be recovered from customers in the future.

Franchise Agreements

In July 2021, SDG&E’s natural gas and electric franchise agreements for the City of San Diego went into effect. These franchise agreements provide SDG&E the opportunity to serve the City of San Diego for a period of 20 years, consisting of 10-year agreements that will automatically renew for an additional 10 years unless the City Council voids the automatic renewals. At December 31, 2024, SDG&E has commitments to make future principal and interest payments as consideration for the franchise agreements of $14 million in 2025, $4 million in 2026, $2 million in each of 2027 through 2029 and $45 million thereafter. The consideration paid will not be recovered from customers and will be amortized over 20 years.

2024 Form 10-K | F-135

Other Sempra

Additional consideration for a 2006 comprehensive legal settlement with California to resolve the Continental Forge litigation included an agreement that, for a period of 18 years beginning in 2011, Sempra Infrastructure would sell to SDG&E and SoCalGas, subject to annual CPUC approval, up to 500 MMcf per day of regasified LNG from Sempra Infrastructure’s ECA Regas Facility that is not delivered or sold in Mexico at the price indexed to the California border minus $0.02 per MMBtu. There are no specified minimums required, and to date, Sempra Infrastructure has not been required to deliver any natural gas pursuant to this agreement.

ENVIRONMENTAL ISSUES

Our operations are subject to federal, state and local environmental laws. We also are subject to regulations related to hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. These laws and regulations require that we investigate and correct the effects of the release or disposal of materials at sites associated with our past and our present operations. These sites include those at which we have been identified as a PRP under the federal Superfund laws and similar state laws.

In addition, we are required to obtain numerous governmental permits, licenses and other approvals to construct facilities and operate our businesses. The related costs of environmental monitoring, pollution control equipment, cleanup costs, and emissions fees are significant. Increasing national and international concerns regarding global warming and mercury, carbon dioxide, nitrogen oxide and sulfur dioxide emissions could result in requirements for additional pollution control equipment or significant emissions fees or taxes that could adversely affect Sempra Infrastructure. SDG&E’s and SoCalGas’ costs to operate their facilities in compliance with these laws and regulations generally have been recovered in customer rates.

We disclose any proceeding under environmental laws to which a government authority is a party when the potential monetary sanctions, exclusive of interest and costs, exceed the lesser of $1 million or 1% of current assets, which was $53 million for Sempra, $13 million for SDG&E and $16 million for SoCalGas at December 31, 2024.

Other Environmental Issues

We generally capitalize the significant costs we incur to mitigate or prevent future environmental contamination or extend the life, increase the capacity, or improve the safety or efficiency of property used in current operations. The following table shows our capital expenditures (including construction work in progress) in order to comply with environmental laws and regulations:

CAPITAL EXPENDITURES FOR ENVIRONMENTAL ISSUES
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Sempra	$	65	$	107	$	87
SDG&E	23		29		31
SoCalGas	42		78		56

We have not identified any significant environmental issues outside the U.S.

At SDG&E and SoCalGas, costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the probability that these costs will be recovered in rates.

The environmental issues currently facing us, except for those resolved during the last three years, include (1) investigation and remediation of SDG&E’s and SoCalGas’ manufactured-gas sites, (2) cleanup of third-party waste-disposal sites used by SDG&E and SoCalGas at which we have been identified as a PRP and (3) mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS.

2024 Form 10-K | F-136

The table below shows the status at December 31, 2024 of SDG&E’s and SoCalGas’ manufactured-gas sites and the third-party waste-disposal sites for which we have been identified as a PRP:

STATUS OF ENVIRONMENTAL SITES
	# Sites complete(1)	# Sites in process
SDG&E:
Manufactured-gas sites	3	—
Third-party waste-disposal sites	2	1
SoCalGas:
Manufactured-gas sites	39	3
Third-party waste-disposal sites	5	2

(1)    There may be ongoing compliance obligations for completed sites, such as regular inspections, adherence to land use covenants and water quality monitoring.

We record environmental liabilities when our liability is probable and the costs can be reasonably estimated. In many cases, however, investigations are not yet at a stage where we can determine whether we are liable or, if the liability is probable, to reasonably estimate the amount or range of amounts of the costs. Estimates of our liability are further subject to uncertainties such as the nature and extent of site contamination, evolving cleanup standards and imprecise engineering evaluations. We review our accruals periodically and, as investigations and cleanups proceed, we make adjustments as necessary.

The following table shows our accrued liabilities for environmental matters at December 31, 2024. Of the total liability, $14 million at SoCalGas is recorded on a discounted basis, with a weighted-average discount rate of 2.45%.

ACCRUED LIABILITIES FOR ENVIRONMENTAL MATTERS
(Dollars in millions)
	Sempra(1)		SDG&E(1)		SoCalGas
Manufactured-gas sites	$	34	$	—	$	34
Waste disposal sites (PRP)(2)	8		5		3
Other hazardous waste sites	12		11		1
Total(3)	$	54	$	16	$	38

(1)    Does not include SDG&E’s liability for SONGS marine environment mitigation.

(2)     Sites for which we have been identified as a PRP.

(3)    Includes $6, $1, $5 classified as current liabilities and $48, $15 and $33 classified as noncurrent liabilities on Sempra’s, SDG&E’s and SoCalGas’ Consolidated Balance Sheets, respectively.

We expect future payments related to our environmental liabilities on an undiscounted basis to be $6 million in 2025, $4 million in 2026, $8 million in 2027, $24 million in 2028, $1 million in 2029 and $14 million thereafter.

In connection with the issuance of operating permits, SDG&E and the other owners of SONGS previously reached an agreement with the California Coastal Commission to mitigate the damage to the marine environment caused by the cooling-water discharge from SONGS during its operation. SONGS’ early retirement, described in Note 14, does not reduce SDG&E’s mitigation obligation. SDG&E’s share of the estimated mitigation costs is $154 million, of which $56 million has been incurred through December 31, 2024 and $98 million is accrued for remaining costs through 2059, which is recoverable in rates and included in noncurrent Regulatory Assets on Sempra’s and SDG&E’s Consolidated Balance Sheets.

2024 Form 10-K | F-137

NOTE 16. SEGMENT INFORMATION

SEMPRA

Sempra is a California-based holding company whose businesses invest in, develop and operate energy infrastructure in North America and provide electric and gas services to customers. Sempra has the following three operating and reportable segments, which are managed separately based on services provided, geographic location and regulatory framework:

▪Sempra California provides natural gas and electric service to Southern California and part of central California through Sempra’s wholly owned subsidiaries, SDG&E and SoCalGas, which are regulated public utilities.

▪Sempra Texas Utilities holds our equity method investment in Oncor Holdings, which owns an 80.25% interest in Oncor, a regulated electric transmission and distribution utility serving customers in the north-central, eastern, western and panhandle regions of Texas; and our equity method investment in Sharyland Holdings, which owns Sharyland Utilities, a regulated electric transmission utility serving customers near the Texas-Mexico border.

▪Sempra Infrastructure includes the operating companies of SI Partners, in which Sempra Infrastructure owns a 70% interest, as well as a holding company and certain services companies. Sempra Infrastructure develops, builds, operates and invests in energy infrastructure to help provide safe, sustainable and reliable access to cleaner energy in markets in the U.S., Mexico and globally.

Sempra’s CODM, who is its chief executive officer, uses segment earnings attributable to common shares predominantly in the annual financial planning process to assess financial performance. Sempra’s CODM prioritizes resource allocation to each segment in a manner that aligns with Sempra’s capital expenditures plan, which is focused on safety, reliability and modernization of its segments’ infrastructure while supporting customer affordability; investing in incremental infrastructure growth projects with attractive risk-adjusted returns; maintaining a strong balance sheet; and returning cash to shareholders.

The accounting policies of the segments are consistent with those described in the summary of significant accounting policies in Note 1. Sempra accounts for intersegment sales as if the sales were to third parties, that is, at current market prices. The cost of common services shared by the reportable segments is assigned directly or allocated based on various cost factors, depending on the nature of the service provided. Parent and other allocates depreciation expense to the reportable segments without allocating the related depreciable assets to those reportable segments. Interest income and interest expense are recorded on intersegment loans. We have eliminated intersegment accounts and transactions within Sempra’s consolidated financial statements. Amounts labeled as “Parent and other,” which does not meet the definition of an operating or reportable segment, consist primarily of activities of parent organizations.

2024 Form 10-K | F-138

The following tables present selected information by segment and reconciliations of assets, capital expenditures for PP&E, and earnings attributable to common shares to Sempra’s consolidated totals.

SEGMENT INFORMATION
(Dollars in millions)
			December 31,
			2024		2023
ASSETS
Sempra California			$	56,116	$	53,430
Sempra Texas Utilities			15,534		14,392
Sempra Infrastructure			22,954		19,430
Segment totals			94,604		87,252
Parent and other			2,622		967
Intersegment eliminations(1)			(1,071)		(1,038)
Total Sempra			$	96,155	$	87,181
EQUITY METHOD INVESTMENTS
Sempra Texas Utilities			$	15,522	$	14,380
Sempra Infrastructure			2,411		2,129
Segment totals/Total Sempra			$	17,933	$	16,509
GEOGRAPHIC LOCATION OF PROPERTY, PLANT AND EQUIPMENT, NET
United States			$	52,952	$	46,935
Mexico			8,485		8,024
Rest of the world			—		1
Total Sempra			$	61,437	$	54,960
	Years ended December 31,
	2024		2023		2022
CAPITAL EXPENDITURES FOR PROPERTY, PLANT AND EQUIPMENT
Sempra California	$	4,753	$	4,560	$	4,466
Sempra Infrastructure	3,459		3,832		884
Segment totals	8,212		8,392		5,350
Parent and other	3		5		7
Total Sempra	$	8,215	$	8,397	$	5,357
GEOGRAPHIC LOCATION OF REVENUES(2)
United States	$	11,623	$	14,973	$	13,015
Mexico	1,562		1,747		1,424
Total Sempra	$	13,185	$	16,720	$	14,439

(1)     Primarily includes an intersegment loan from Sempra Infrastructure to Parent and other related to deferred income taxes.

(2)     Amounts are based on where the revenue originated, after intersegment eliminations.

2024 Form 10-K | F-139

SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
	Sempra California		Sempra Texas Utilities(1)		Sempra Infrastructure		Sempra
	Year ended December 31, 2024
Revenues	$	11,382			$	1,882
Depreciation and amortization	(2,133)				(297)
Interest income	14				25
Interest expense(2)	(848)				243
Income tax (expense) benefit	(184)				164
Equity earnings	—		$	788	802
Earnings attributable to noncontrolling interests	—		—		(638)
Other segment items(3)	(6,385)		(7)		(1,270)
Segment earnings attributable to common shares	$	1,846	$	781	$	911	$	3,538
Parent and other							(721)
Earnings attributable to common shares							$	2,817
	Year ended December 31, 2023
Revenues	$	13,761			$	3,071
Depreciation and amortization	(1,937)				(281)
Interest income	24				43
Interest expense(2)	(782)				(129)
Income tax benefit (expense)	31				(673)
Equity earnings	—		$	701	740
Earnings attributable to noncontrolling interests	—		—		(543)
Other segment items(3)	(9,350)		(7)		(1,351)
Segment earnings attributable to common shares	$	1,747	$	694	$	877	$	3,318
Parent and other							(288)
Earnings attributable to common shares							$	3,030
	Year ended December 31, 2022
Revenues	$	12,577			$	1,919
Depreciation and amortization	(1,743)				(268)
Interest income	11				44
Interest expense	(647)				(104)
Income tax expense	(320)				(249)
Equity earnings	—		$	742	756
Earnings attributable to noncontrolling interests	—		—		(146)
Other segment items(3)	(8,364)		(6)		(1,642)
Segment earnings attributable to common shares	$	1,514	$	736	$	310	$	2,560
Parent and other							(466)
Earnings attributable to common shares							$	2,094

(1)    Substantially all earnings attributable to common shares are from equity earnings.

(2)    Sempra Infrastructure includes net unrealized gains (losses) from undesignated interest rate swaps related to the PA LNG Phase 1 project.

(3)    Includes cost of natural gas, cost of electric fuel and purchased power, O&M, Aliso Canyon litigation and regulatory matters, franchise fees and other taxes, other income (expense), net, and preferred dividends for Sempra California; O&M, interest expense, and income tax expense (benefit) for Sempra Texas Utilities related to activities at the holding company; and cost of natural gas, energy-related businesses cost of sales, O&M, franchise fees and other taxes, and other income (expense), net, for Sempra Infrastructure.

2024 Form 10-K | F-140

The following table presents revenues by services by segment, reconciled to Sempra’s consolidated revenues.

REVENUES BY SERVICES
(Dollars in millions)
	Sempra California		Sempra Infrastructure		Sempra
	Year ended December 31, 2024
Revenues from external customers:
Utilities	$	10,985	$	78
Energy-related businesses	—		755
Total revenues from external customers(1)	10,985		833		$	11,818
Other revenues(2):
Utilities	374		—
Energy-related businesses	—		993
Total other revenues	374		993		1,367
Intersegment revenues(3):
Utilities	23		—
Energy-related businesses	—		56
Total intersegment revenues	23		56		79
Segment revenues	$	11,382	$	1,882	13,264
Intersegment eliminations					(79)
Revenues					$	13,185
	Year ended December 31, 2023
Revenues from external customers:
Utilities	$	13,668	$	87
Energy-related businesses	—		1,094
Total revenues from external customers(1)	13,668		1,181		$	14,849
Other revenues(2):
Utilities	75		—
Energy-related businesses	—		1,796
Total other revenues	75		1,796		1,871
Intersegment revenues(3):
Utilities	18		—
Energy-related businesses	—		94
Total intersegment revenues	18		94		112
Segment revenues	$	13,761	$	3,071	16,832
Intersegment eliminations					(112)
Revenues					$	16,720
	Year ended December 31, 2022
Revenues from external customers:
Utilities	$	11,930	$	89
Energy-related businesses	—		1,704
Total revenues from external customers(1)	11,930		1,793		$	13,723
Other revenues(2):
Utilities	633		—
Energy-related businesses	—		83
Total other revenues	633		83		716
Intersegment revenues(3):
Utilities	14		—
Energy-related businesses	—		43
Total intersegment revenues	14		43		57
Segment revenues	$	12,577	$	1,919	14,496
Intersegment eliminations					(57)
Revenues					$	14,439

(1)    We did not have revenues from transactions with a single external customer that amounted to 10% or more of Sempra’s total revenues.

(2)    See “Revenues from Sources Other Than Contracts with Customers” in Note 3 for a description of this revenue source, which may be additive or subtractive from period to period.

(3)    See “Transactions with Affiliates” in Note 1 for a description of services provided by one operating segment to another operating segment within Sempra.

2024 Form 10-K | F-141

SDG&E

SDG&E is a regulated public utility that provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County. SDG&E has one operating and reportable segment.

SDG&E’s CODM, who is its chief executive officer, utilizes earnings attributable to common shares to manage the business, assess performance and allocate resources. SDG&E’s CODM allocates resources to support the delivery of safe, reliable and affordable energy to customers.

Total assets at SDG&E were $30.8 billion and $29.2 billion at December 31, 2024 and 2023, respectively. The following table presents selected information for SDG&E’s single segment and reconciliation of earnings attributable to common shares.

SEGMENT INFORMATION
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
SDG&E:
Revenues from external customers:
Electric	$	4,164	$	4,750	$	4,687
Natural gas	878		1,204		899
Total revenues from external customers(1)	5,042		5,954		5,586
Other revenues(2):
Electric	149		(401)		109
Natural gas	150		44		143
Total other revenues	299		(357)		252
Total revenues	5,341		5,597		5,838
Depreciation and amortization	(1,223)		(1,098)		(982)
Interest income	5		15		5
Interest expense	(525)		(497)		(449)
Income tax (expense) benefit	(153)		26		(182)
Other segment items(3)	(2,554)		(3,107)		(3,315)
Earnings attributable to common shares	$	891	$	936	$	915
Capital expenditures for property, plant and equipment	$	2,522	$	2,540	$	2,473

(1)    We did not have revenues from transactions with a single external customer that amounted to 10% or more of SDG&E’s total revenues.

(2)    See “Revenues from Sources Other Than Contracts with Customers” in Note 3 for a description of this revenue source, which may be additive or subtractive from period to period.

(3)    Includes cost of electric fuel and purchased power, cost of natural gas, O&M, franchise fees and other taxes, and other income (expense), net.

2024 Form 10-K | F-142

SOCALGAS

SoCalGas is a regulated public natural gas distribution utility, serving customers throughout most of Southern California and part of central California. SoCalGas has one operating and reportable segment.

SoCalGas’ CODM, who is its chief executive officer, utilizes earnings attributable to common shares to manage the business, assess performance and allocate resources. SoCalGas’ CODM allocates resources to support the delivery of safe, reliable and affordable energy to customers.

Total assets at SoCalGas were $25.4 billion and $24.3 billion at December 31, 2024 and 2023, respectively. The following table presents selected information for SoCalGas’ single segment and reconciliation of earnings attributable to common shares.

SEGMENT INFORMATION
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
SoCalGas:
Natural gas:
Revenues from external customers(1)	$	6,134	$	7,857	$	6,459
Other revenues(2)	75		432		381
Total revenues	6,209		8,289		6,840
Aliso Canyon litigation and regulatory matters	—		—		(259)
Depreciation and amortization	(910)		(839)		(761)
Interest income	9		9		6
Interest expense	(323)		(285)		(198)
Income tax (expense) benefit	(31)		5		(138)
Other segment items(3)	(3,999)		(6,368)		(4,891)
Earnings attributable to common shares	$	955	$	811	$	599
Capital expenditures for property, plant and equipment	$	2,231	$	2,020	$	1,993

(1)    We did not have revenues from transactions with a single external customer that amounted to 10% or more of SoCalGas’ total revenues.

(2)    See “Revenues from Sources Other Than Contracts with Customers” in Note 3 for a description of this revenue source, which may be additive or subtractive from period to period.

(3)    Includes cost of natural gas, O&M, franchise fees and other taxes, and other income (expense), net, and preferred dividends.

2024 Form 10-K | F-143

SCHEDULE I – SEMPRA
INDEX TO CONDENSED FINANCIAL INFORMATION OF PARENT
Condensed Statements of Operations for the years ended December 31, 2024, 2023 and 2022	S-2
Condensed Statements of Comprehensive Income (Loss) for the years ended December 31, 2024, 2023 and 2022	S-3
Condensed Balance Sheets at December 31, 2024 and 2023	S-4
Condensed Statements of Cash Flows for the years ended December 31, 2024, 2023 and 2022	S-5
Notes to Condensed Financial Information of Parent
Note 1. Basis of Presentation	S-6
Note 2. New Accounting Standards	S-6
Note 3. Debt and Credit Facility	S-6
Note 4. Commitments and Contingencies	S-8

2024 Form 10-K | S-1

SEMPRA
CONDENSED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts; shares in thousands)
	Years ended December 31,
	2024		2023		2022
Interest income	$	29	$	31	$	35
Interest expense	(490)		(444)		(326)
Operating expenses	(105)		(101)		(92)
Other income (expense), net	25		31		(58)
Income tax benefit	165		134		111
Loss before equity in earnings of subsidiaries	(376)		(349)		(330)
Equity in earnings of subsidiaries, net of income taxes	3,237		3,423		2,468
Net income	2,861		3,074		2,138
Preferred dividends	(44)		(44)		(44)
Earnings	$	2,817	$	3,030	$	2,094
Basic EPS:
Earnings	$	4.44	$	4.81	$	3.32
Weighted-average common shares outstanding	633,795		630,296		630,318
Diluted EPS:
Earnings	$	4.42	$	4.79	$	3.31
Weighted-average common shares outstanding	637,943		632,733		632,757

See Notes to Condensed Financial Information of Parent.

2024 Form 10-K | S-2

SEMPRA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Years ended December 31, 2024, 2023 and 2022
	Pretax amount		Income tax benefit (expense)		Net-of-tax amount
2024:
Net income	$	2,696	$	165	$	2,861
Other comprehensive income (loss):
Foreign currency translation adjustments	(30)		—		(30)
Financial instruments	14		(2)		12
Pension and other postretirement benefits	18		(16)		2
Total other comprehensive income (loss)	2		(18)		(16)
Comprehensive income	$	2,698	$	147	$	2,845
2023:
Net income	$	2,940	$	134	$	3,074
Other comprehensive income (loss):
Foreign currency translation adjustments	23		—		23
Financial instruments	57		(18)		39
Pension and other postretirement benefits	(39)		8		(31)
Total other comprehensive income	41		(10)		31
Comprehensive income	$	2,981	$	124	$	3,105
2022:
Net income	$	2,027	$	111	$	2,138
Other comprehensive income (loss):
Foreign currency translation adjustments	11		—		11
Financial instruments	221		(55)		166
Pension and other postretirement benefits	3		(6)		(3)
Total other comprehensive income	235		(61)		174
Comprehensive income	$	2,262	$	50	$	2,312

See Notes to Condensed Financial Information of Parent.

2024 Form 10-K | S-3

SEMPRA
CONDENSED BALANCE SHEETS
(Dollars in millions)
	December 31,
	2024		2023
Assets:
Cash and cash equivalents	$	1,416	$	3
Restricted cash	2		2
Due from affiliates	88		105
Income taxes receivable, net	71		—
Other current assets	10		11
Total current assets	1,587		121
Investments in subsidiaries	42,305		38,499
Due from affiliates	25		18
Deferred income taxes	209		429
Other long-term assets	1,152		1,095
Total assets	$	45,278	$	40,162
Liabilities and shareholders’ equity:
Short-term debt	$	—	$	365
Due to affiliates	241		235
Other current liabilities	1,410		819
Total current liabilities	1,651		1,419
Long-term debt	11,028		8,461
Due to affiliates	739		988
Other long-term liabilities	638		619
Commitments and contingencies (Note 4)
Shareholders’ equity	31,222		28,675
Total liabilities and shareholders’ equity	$	45,278	$	40,162

See Notes to Condensed Financial Information of Parent.

2024 Form 10-K | S-4

SEMPRA
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2024		2023		2022
Net cash provided by operating activities	$	120	$	1,576	$	775
Expenditures for property, plant and equipment	(3)		(5)		(7)
Proceeds from sale of assets	—		2		—
Capital contributions to investees	(933)		(1,749)		(661)
Distributions from investments	9		108		—
Purchases of trust assets	(63)		(78)		(114)
Proceeds from sales of trust assets	68		69		123
Increase in loans to affiliates, net	(117)		(90)		(92)
Premiums on corporate-owned life insurance policies	(1)		(1)		(3)
Net cash used in investing activities	(1,040)		(1,744)		(754)
Common dividends paid	(1,499)		(1,483)		(1,430)
Preferred dividends paid	(44)		(44)		(44)
Issuances of common stock, net	1,219		145		4
Repurchases of common stock	(43)		(32)		(478)
Issuances of debt (maturities greater than 90 days)	3,695		1,918		1,569
Payments on debt (maturities greater than 90 days)	(350)		(672)		(322)
Decrease in short-term debt, net	(365)		(89)		(785)
(Decrease) increase in loans from affiliates, net	(241)		220		(226)
Proceeds from sales of noncontrolling interests, net	—		—		1,732
Other	(38)		(10)		(8)
Net cash provided by (used in) financing activities	2,334		(47)		12
Effect of exchange rate changes on cash, cash equivalents and restricted cash	(1)		—		(1)
Increase (decrease) in cash, cash equivalents and restricted cash	1,413		(215)		32
Cash, cash equivalents and restricted cash, January 1	5		220		188
Cash, cash equivalents and restricted cash, December 31	$	1,418	$	5	$	220
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued interest receivable capitalized to note receivable	$	17	$	16	$	18
Preferred dividends declared but not paid	11		11		11
Common dividends declared but not paid	393		376		360
Common dividends issued in stock	54		—		—
Net exercise of stock options	9		—		—
Equitization of amounts due from affiliates	110		92		93

See Notes to Condensed Financial Information of Parent.

2024 Form 10-K | S-5

NOTES TO CONDENSED FINANCIAL INFORMATION OF PARENT

NOTE 1. BASIS OF PRESENTATION

The condensed financial information of Sempra has been prepared in accordance with SEC Regulation S-X Rule 5-04 and Rule 12-04. We apply the same accounting policies as in the consolidated financial statements of Sempra, except that Sempra accounts for the earnings of its subsidiaries under the equity method in this unconsolidated financial information. This financial information should be read in conjunction with Sempra’s consolidated financial statements and the accompanying notes thereto included in this Form 10-K.

Sempra received cash dividends from its subsidiaries totaling $908 million, $1.9 billion and $832 million in 2024, 2023 and 2022, respectively.

NOTE 2. NEW ACCOUNTING STANDARDS

We describe in Note 2 of the Notes to Consolidated Financial Statements recent pronouncements that have had or may have a significant effect on Sempra’s results of operations, financial condition, cash flows or disclosures.

NOTE 3. DEBT AND CREDIT FACILITY

SHORT-TERM DEBT

Committed Line of Credit

At December 31, 2024, Sempra had capacity of $4.0 billion under a committed line of credit, which provides liquidity and supports its commercial paper program, with available unused credit of $4.0 billion before reductions of any unamortized discounts.

The principal terms of Sempra’s committed line of credit include the following:

▪The facility has a syndicate of 23 lenders. No single lender has greater than a 6% share in the facility.

▪The facility provides for the issuance of $200 million of letters of credit. Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, Sempra has the right to increase its letter of credit commitment to up to $500 million. No letters of credit were outstanding at December 31, 2024.

▪Borrowings bear interest at a benchmark rate plus a margin that varies with Sempra’s credit rating.

▪Sempra must maintain a ratio of indebtedness to total capitalization (as defined in its credit facility) of no more than 65% at the end of each quarter. At December 31, 2024, Sempra was in compliance with this ratio under its credit facility.

2024 Form 10-K | S-6

LONG-TERM DEBT

The following table shows the detail and maturities of uncollateralized long-term debt outstanding.

LONG-TERM DEBT
(Dollars in millions)
	December 31,
	2024		2023
3.30% Notes April 1, 2025	$	750	$	750
5.40% Notes August 1, 2026	550		550
3.25% Notes June 15, 2027	750		750
3.40% Notes February 1, 2028	1,000		1,000
3.70% Notes April 1, 2029	500		500
5.50% Notes August 1, 2033	700		700
3.80% Notes February 1, 2038	1,000		1,000
6.00% Notes October 15, 2039	750		750
4.00% Notes February 1, 2048	800		800
4.125% (next rate reset on April 1, 2027) Junior Subordinated Notes April 1, 2052(1)	1,000		1,000
6.40% (next rate reset on October 1, 2034) Junior Subordinated Notes October 1, 2054(1)	1,250		—
6.875% (next rate reset on October 1, 2029) Junior Subordinated Notes October 1, 2054(1)	600		—
6.875% (next rate reset on October 1, 2029) Junior Subordinated Notes October 1, 2054(1)	500		—
6.55% (next rate reset on April 1, 2035) Junior Subordinated Notes April 1, 2055(1)	600		—
6.625% (next rate reset on April 1, 2030) Junior Subordinated Notes April 1, 2055(1)	400		—
5.75% Junior Subordinated Notes July 1, 2079(1)	758		758
	11,908		8,558
Current portion of long-term debt	(750)		—
Unamortized discount on long-term debt	(30)		(29)
Unamortized debt issuance costs	(100)		(68)
Total long-term debt	$	11,028	$	8,461

(1)    Callable long-term debt not subject to make-whole provisions.

Sempra issued the following fixed-to-fixed reset rate junior subordinated notes in 2024:

▪In March 2024, Sempra issued $600 million aggregate principal amount of 6.875% junior subordinated notes maturing on October 1, 2054, and received proceeds of $593 million (net of debt discount, underwriting discounts and debt issuance costs of $7 million). In May 2024, Sempra issued an additional $500 million aggregate principal amount of these junior subordinated notes and received proceeds of $489 million (net of debt discount, underwriting discounts and debt issuance costs of $11 million, but excluding $7 million paid to us in respect of accrued interest from and including March 14, 2024 to, but excluding, May 31, 2024. Interest accrues from and including March 14, 2024 to, but excluding, October 1, 2029 at the rate of 6.875% per annum.

▪In September 2024, Sempra issued $1.25 billion aggregate principal amount of 6.40% junior subordinated notes maturing on October 1, 2054, and received proceeds of $1.235 billion (net of underwriting discounts and debt issuance costs of $15 million). Interest accrues from and including September 9, 2024 to, but excluding, October 1, 2034 at the rate of 6.40% per annum.

▪In November 2024, Sempra issued $400 million aggregate principal amount of 6.625% junior subordinated notes maturing on April 1, 2055, and received proceeds of $395 million (net of underwriting discounts and debt issuance costs of $5 million). Interest accrues from and including November 21, 2024 to, but excluding, April 1, 2030 at the rate of 6.625% per annum.

▪In November 2024, Sempra issued $600 million aggregate principal amount of 6.55% junior subordinated notes maturing on April 1, 2055, and received proceeds of $593 million (net of underwriting discounts and debt issuance costs of $7 million). Interest accrues from and including November 21, 2024 to, but excluding, April 1, 2035 at the rate of 6.55% per annum.

The interest rates on the notes will be reset on:

▪October 1, 2029 (for the March 2024 and May 2024 issuances),

▪October 1, 2034 (for the September 2024 issuance),

▪April 1, 2030 (for the $400 million November 2024 issuance), and

▪April 1, 2035 (for the $600 million November 2024 issuance),

and on each subsequent five-year period beginning on October 1 or April 1, as applicable, of every fifth year thereafter, at a rate per annum equal to the Five-year U.S. Treasury Rate (as defined in the notes) as of the day falling two business days before the first day of such five-year period plus a spread of:

2024 Form 10-K | S-7

▪2.789% (for the March 2024 and May 2024 issuances),

▪2.632% (for the September 2024 issuance),

▪2.354% (for the $400 million November 2024 issuance), and

▪2.138% (for the $600 million November 2024 issuance).

Interest is payable on the notes semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2024 (for the March 2024 and May 2024 issuances) or April 1, 2025 (for the September 2024 and November 2024 issuances).

We may redeem some or all of the notes before their maturity, as follows:

▪in whole or in part, (i) on any day in the period commencing on the date falling 90 days prior to, and ending on and including October 1, 2029 (for the March 2024 and May 2024 issuances), October 1, 2034 (for the September 2024 issuance), April 1, 2030 (for the $400 million November 2024 issuance), and April 1, 2035 (for the $600 million November 2024 issuance), and (ii) after those respective dates, on any interest payment date, at a redemption price in cash equal to 100% of the principal amount of the notes being redeemed, plus, subject to the terms of the notes, accrued and unpaid interest on the notes to be redeemed to, but excluding, the redemption date;

▪in whole but not in part, at any time following the occurrence and during the continuance of a tax event (as defined in the notes) at a redemption price in cash equal to 100% of the principal amount of the notes, plus, subject to the terms of the notes, accrued and unpaid interest on the notes to, but excluding, the redemption date; and

▪in whole but not in part, at any time following the occurrence and during the continuance of a rating agency event (as defined in the notes) at a redemption price in cash equal to 102% of the principal amount of the notes, plus, subject to the terms of the notes, accrued and unpaid interest on the notes to, but excluding, the redemption date.

The notes described above are unsecured obligations and rank junior and subordinate in right of payment to our existing and future senior indebtedness. The notes rank equally in right of payment with each other and with our existing 4.125% fixed-to-fixed reset rate junior subordinated notes due 2052 and 5.75% junior subordinated notes due 2079 and with any future unsecured indebtedness that we may incur if the terms of such indebtedness provide that it ranks equally with the notes in right of payment. The notes are effectively subordinated in right of payment to any secured indebtedness we have incurred or may incur (to the extent of the value of the collateral securing such secured indebtedness) and to all existing and future indebtedness and other liabilities and any preferred equity of our subsidiaries.

We used, or plan to use, the proceeds from the offerings for general corporate purposes, including repayment of commercial paper and other indebtedness.

At December 31, 2024, scheduled maturities of Sempra’s long-term debt are $750 million in 2025, $550 million in 2026, $750 million in 2027, $1.0 billion in 2028, $500 million in 2029 and $8.4 billion thereafter.

Additional information on Sempra’s short-term and long-term debt is provided in Note 6 of the Notes to Consolidated Financial Statements.

NOTE 4. COMMITMENTS AND CONTINGENCIES

At December 31, 2024, Sempra has an operating lease liability related to its corporate headquarters building of approximately $147 million. Sempra expects undiscounted lease payments for its operating lease to be $12 million in each of 2025 through 2028, $13 million in 2029 and $151 million thereafter through 2040 for a total of $212 million. The operating lease cost was $14 million at December 31, 2024, 2023 and 2022. The weighted-average discount rate of the lease is 4.7% at December 31, 2024 and 2023.

For other contingencies and guarantees related to Sempra, refer to Notes 5 and 15 of the Notes to Consolidated Financial Statements.

2024 Form 10-K | S-8